Report No. 14586-MOG Mongol ia Energy Sector Review November 3, 1995 ESMAP/Power Development Efficiency and Household Fuels Division Industry and Energy Department Finance and Private Sector Development Office Industry and Energy Division China and Mongolia Department East Asia and Pacific Regional Office >~~~~~~~~~~~~~~~~~~~, = *E F~~~A .. AlX6 i i' t ' Currency Equivalents Currency Unit = Tugrik (Tug.) Before November 1991: $1.00 = Tug. 7 (barter rate) As of June 30, 1992: $1.00 = Tug. 40 (for official transaction) $1.00 = Tug. 250 (for free market transaction) As of April 30, 1993: $1.00 = Tug. 150 (for official transaction) $1.00 = Tug. 420 (for free market transaction) As of May 31, 1993: $1.00 = Tug. 400 (unified free market exchange rate) As of December 31, 1994: $1.00 = Tug. 410 (unified free market exchange rate) Fiscal Year January I - December 31 Abbreviations and Acronyms ADB Asian Development Bank BNCC Baga Nuur Coal Company BOO Build Own Operate BOT Build Own Transfer CES Central Energy System CHP Combined heat and power (plants) CIS Commonwealth of Independent States CMEA Council for Mutual Economic Assistance DH District Heating DGT Diesel Fueled Gas Turbine EUO Energy Utility Organization FSU Former Soviet Union GDP Gross Domestic Product GOM Government of Mongolia GWh Gigawatt hours HOB Heat-only-boiler IPP Independent Power Producer kcal kilocalories kWh kilowatt hours LRMC Long Run Marginal Cost MEGM Ministry of Energy, Geology and Mining MIS Management Information System MOF Ministry of Finance MR Mongolian Railways MTI Ministry of Trade and Industry mtoe metric tonnes oil equivalent MW megawatts NIC Neft Import Concern PSC Price Setting Committee SSO State Statistical Office SFC Specific Fuel Consumption TA Technical Assistance UB Ulaanbaatar Foreword This report was developed by a team including S. Rivera (Task Manager), R. Taylor (Senior Energy Economist) and J. Escay (Consultant), C. Wardell (Principal Mining Engineer) on the coal sector; S. Kataoka (Senior Power Engineer), H. Campero and 0. Pfluger (Consultants) on the power sector; F. Lauritsen (Consultant) on district heating; A. Cabraal (Consultant) on isolated energy systems; and B. Svensson (Energy Economist) on downstream petroleum operations. N. Chakwin (Consultant, economist) contributed to reviewing the report. The main mission visited Ulaanbaatar during November 1994 and the report was discussed with the Government on July 3-7, 1995. The mission is most grateful for the assistance provided by the Ministry of Energy, Geology and Mining and its Energy Conservation Cell; Ministry of Finance; Neft Import Concern; CES; NUURS Company; the Institute of Renewable Energy and the State Statistical Office. The mission also remains indebted to the Aimak governments of Bayan Hongor and Dzavhan for their most effective support. The report was reviewed by Messrs. M. Del Buono, K. Schenk (IENPD) and E. Crousillat (EAIIE). The Division Chief is Richard G. Scurfield, and the Department Director is Nicholas C. Hope. Contents Executive Summary ..............................................................i Background ...............................................................i Development Priorities and Strategy .............................................................. ii Institutional Reform and Incentives to Ensure Reliable Energy Services ........................... iii Energy Pricing and Financial Sustainability ...............................................................v Restructuring Energy Companies .............................................................. vii Investment Priorities .............................................................. viii Next Steps and International Assistance .............................. .................................x I. Energy Sector Overview ...............................................................1 Economic Adjustment and Sector Reform ...............................................................1 Overview of the Energy Sector ...............................................................3 Demand Issues ...............................................................3 Institutional and Regulatory Framework ...............................................................6 II. Coal Sector .............................................................. 10 Exploiting its Main Indigenous Energy Resource .............................................................. 10 Reserves, Production, and Demand .............................................................. 10 Pricing and Financial Situation of Coal Companies .......................................................... 13 Priorities for the Coal Sector .............................................................. 14 Recommended Action Plan .............................................................. 22 Ill. Combined Heat and Power System .............................................................. 24 Balancing Heat and Electricity Requirements .............................................................. 24 Overview of the CHP System .............................................................. 25 Heat and Electricity Demand .............................................................. 27 Heat and Electricity Supply .............................................................. 29 Financial Performance and Cost of Supply .............................................................. 31 Options to Increase Efficiency in the Near-Term .............................................................. 35 Security of Supply and Reliability of CHP System ............................................................ 41 Recommended Action Plan .............................................................. 43 IV. Isolated Energy Systems .............................................................. 44 The Need for Change .............................................................. 44 Isolated Energy Supply and Demand .............................................................. 44 Pricing .............................................................. 45 Courses of Action to Achieve Sustainability .............................................................. 47 Recommended Action Plan .............................................................. 50 V. Downstream Petroleum Operations .............................................................. 52 Regional Trends and Reliability of Supply .............................................................. 52 Petroleum Products Supply and Demand .............................................................. 53 Pricing .............................................................. 54 Privatization: Institutional Aspects .............................................................. 58 Courses of Action to Improve Supply Reliability and Distribution Efficiency ..................... 59 Recommended Action Plan .............................................................. 62 Annexes Annex 1 Commercial Energy Balance Sheet (mtoe) ......................................... 64 Annex 2 Four-Year Rehabilitation Plan CHP Plant No. 4 .............................................................. 65 Executive Summary 1. The collapse of the assistance from the former Soviet Union in 1990 pushed the economy into deep recession and the energy sector to the brink of crisis. Chronic reliability problems in power and heat supply in one of the world's coldest regions forced policy-makers and external donors to invest in short-term remedies to maintain energy supply. These measures, plus targeted donor assistance, averted a collapse of energy supply but much needed maintenance, especially in the coal-heat- power delivery system, was deferred and decapitalization of the energy sector increased as the overall system deteriorated. 2. Within that context, this review seeks to identify the set of policy and investment priorities needed to increase reliability and security of energy supply while minimizing Government financial transfers to the sector. To do so, the scope of the review focuses on the analysis of the most important elements of the system in the coal- power-heat delivery system in the main urban areas, electricity and heat systems in the isolated towns, and downstream petroleum supply and distribution. Background 3. Mongolia's cities and large towns are constructed around coal-fired combined-heat-and-power (CHP) plants, which provide electricity and district heat to urban residents. Ulaanbaatar, the coldest capital in the world, is dependent upon three such CHP plants of Russian design. The concept of the CHP plant/district heating networks is technically efficient, providing electricity, industrial steam, space heating and domestic hot water from one energy source. However, design constraints in the case of Mongolia limit the system's flexibility. For example, the district heating system is of a constant-flow design. In contrast to Western European systems, heat supply levels can only be adjusted at the CHP plants, and consumers have no means to adjust their heat consumption except to open or close apartment windows. 4. The CHP plants, and many industrial, commercial and residential consumers, rely on domestic lignite coal for fuel. Coal accounts for close to 80 percent of total primary commercial energy use. The country has ample coal reserves, which is primarily mined in open pits and supplied at costs well below those of potential imports. 5. Petroleum products are imported from Russia. Petroleum products account for 19 percent of primary commercial energy use. Most imports and distribution is undertaken by a public/private joint shareholding company, the Neft Import Concern (NIC). - i - 6. Management of the coal-power-heat system is still largely based on the framework put in place under the centrally planned economic order of previous decades. The system is overseen by the Ministry of MEGM. It includes: the CES, which operates the main CHP and district heating systems; the major coal mines, which are almost all state-owned; and the public Energy Utility Organizations (EUOs), which operate the electricity and heating systems in the isolated towns. Lines of responsibility and accountability between MEGM and the energy companies are blurred, and MEGM is involved in many aspects of day-to-day company operations. 7. The Mongolian economy has experienced a difficult period of contraction, from which it is now just beginning to emerge. Energy demand and supply fell sharply as a result--with power and coal output falling by 29 percent and 24 percent, respectively, between 1990 and 1993. Strapped of funds, energy companies have deferred necessary investments and repairs. Many facilities are now in serious disrepair, and supply systems experience chronic reliability problems. Development Priorities and Strategy 8. Energy demand is expected to increase only modestly, without reaching previous peak levels, during the rest of the decade. The key objectives for the medium term are to (a) improve the reliability of energy supply, (b) increase the financial self- sufficiency of the sector, and (c) improve the efficiency of operations. To do so, specific sector actions include: e Stabilization of coal production, followed by modest increases in output, reaching perhaps 7 million tons by 2000 or soon thereafter. Substantial improvements are needed in equipment, productivity, cost control, and coal quality. * Substantial improvements in the self-financing capacity of CES through major electricity/heat price adjustments, reducing direct and indirect government financial transfers provided to the sector, for both operational expenditures and investment, to a level as close to zero as possible by the end of the decade. Substantial improvement in the reliability and quality of electricity and heat supply, and reduction of system losses. Securing of stable, long-term contracts for petroleum products, at least cost and risk to the country. * Stabilization of production and improvements in the efficiency of the isolated energy systems. - iii - 9. The Government has succeeded in the difficult task of steering the sector through a crisis period. However, further reliance on the sector approach of the last few years will not succeed in creating a reliable and sustainable energy system, thus defeating the Government's objective to increase security of supply. The past approach has been characterized by: a) sector administration and management principles that are inconsistent with the emerging market economy; b) electricity and power pricing well below cost, and progressively worsening inter-company arrears arising largely from lack of payment for energy services rendered; and c) international donor assistance focused on short-term investment and repair needs. 10. The following pages present recommendations for a sector development strategy for the balance of the 1990s, including institutional reform, energy price reform, restructuring of energy companies, and investment priorities. Institutional Reform and Incentives to Ensure Reliable Energy Services l1. In the energy sector, successful transition from a planned to market economy requires clear separation of the roles and responsibilities of the government and energy companies. To operate efficiently as business-oriented enterprises, energy companies need to have autonomy over economic decisions and operations. They must be held accountable to their owners, whether public or private, for their financial performance. Government oversight roles should focus on sector policy and clearly defined, legally sanctioned regulation, where required. Where public ownership is retained, the government also needs to play a role as owner, but this role should be undertaken by an agency completely independent from any agencies involved in sector oversight and regulation, to avoid conflict of interest. 12. While agreeing on the above principles, one of the main concerns of the Government is how to ensure--particularly during this transitional period--reliable supply of energy services from the state owned coal and power/heating companies at a reasonable cost. Experience in other countries shows that to create an environment conducive to reliable supply at a reasonable cost, the definition of the following elements is critical: the role of the energy companies--be it public or private companies-- under a commercial or corporate law (to induce accountability); * the separation of ownership of the energy companies from the agency responsible for energy policy and regulation ( to allow transparency and autonomy in management decisions, set equal conditions for new private investors and avoid conflict of interests with policy and/or regulatory decisions); - iv - * adequate energy pricing criteria and mechanisms for all elements in the chain of energy production (to supply sufficient funds to the energy companies to cover their costs) through market mechanisms when competition is viable or through arm's length regulation when it is not; and * the role of the government as policy maker and regulatory authority under an energy law(s) as well as the institutional framework to implement policies and regulation of the law(s). 13. Indeed, in Mongolia the management of NIC, responsible for petroleum supply, functions along the lines of a commercial entity, though there is still interference in pricing decisions, illustrating that business oriented enterprises in the energy sector can operate in Mongolia. This process of separation of roles is summarized below: Table 1: Different Roles t;; ..00 .? .... Pollcy and lReglulation (MEGM). Energy Coompanies Propose and:. ..imp.ement:;: tpolicy: 0.andS sector Operate as business-entities under commercial regulationgl:000l:ft ;;:it ;;;; jf i;-E:f;;;E::;0|;:;i:; :W;; law :;accountable to :shareholder(s), without government subsidies.for operationsd or cap.tal expenditures. Promote-sector investment: Develop hard-budget discipline:1 Monitorfinancial viability of operators Develop financisi management. tools to monitor financial:performance A rding4to regulation in place, issue licenses Comply withtrules set by energy regulatonri and concessionsa : Propose pricing critera and mechanisms for fadjusrtmen tT;; : ;t;;;;:t !:; Setfservcetstandards and monitor compliance Monitor :proper stocks :of fuels: and :supervise enery i mports/exports if there are n ational security concerns -____________________________________ - v - Energy Pricing and Financial Sustainability 14. Achievement of greater financial self-sufficiency and reliability in the energy sector will require bold action on two inter-linked fronts: energy price reform and substantial improvement in the ability of energy companies to collect accounts. Further reform of electricity and heat prices requires greatest attention. Reforms in coal and petroleum product pricing are also needed, but distortions and resulting financial difficulties in these cases are less severe. Power and Heat Prices 15. Today, CES is not a financially viable company. Energy prices are well below the cost of supply. Current revenues can barely cover operating costs and are not sufficient to cover basic maintenance and contribute to future rehabilitation and investments. Depreciation allowances are not adequate. 16. Since 1992, the Government has taken major steps to adjust power and heat tariffs reaching about 50-60 percent of estimated long-run marginal cost (LRMC) for electricity tariffs (from levels as low as 10% in early 1992) and about 30-33 percent of estimated LRMC levels for heat prices. For the future, the Government should assign top priority to electricity price reform, with the goal of attaining LRMC levels by 1998-99 at the latest, through steady price increases over and above the rate of inflation. Substantial increases in heat prices also are necessary. However, given the size of the gap and direct impact on residential consumers, it may not be possible to reach the level of economic costs quickly in the case of heat, so that a slow, steady pace may need to be adopted. Impact of Electricity and Heat Price Adjustments 17. The Government is concerned with the impact of energy price adjustments on household expenditures and inflation. Regarding residential consumers, the proposed electricity and heat tariff adjustment--1 5% and 20% per year in real terms respectively-- would undoubtedly affect consumers, particularly those in the lowest expenditure class. Apartment dwellers account for about 14 percent of electricity use, averaging 2050 Kwh/year in the capital. Electricity expenditures account for about 3.8 percent of total expenditures in these households . Hence, an increase of electricity tariff to the recommended levels in 1996 (68 percent of LRMC) would represent additional expenditures of Tug 96/month for those households consuming 50 Kwh/month. In the absence of meters, current subsidies in the residential sector may be benefiting more those users in the higher income quartile than the poorest. Hence, proper metering of electricity and heat is a priority for the CES if a decision is made to establish subsidies for ISSO- Monthly expenditures of Tug. 39,381 in the capital city - vi - low income consumers below 40-50 Kwh/month (e.g. through a lifeline tariff), particularly if heat prices will take longer time to reach economic levels. 18. This study did not include an assessment of the impact of energy price levels on inflation. However, based on the experience in other countries where this 2 assessment has been carried out in detail , results show that: a) low energy prices, and associated subsidies, directly contribute to the consolidated public sector deficit, which in turn fuels inflation; and b) the gradual elimination of energy subsidies would go a long way toward the creation of incentives for energy conservation, particularly in the industrial sector. With improved incentives for conservation, price increases do not necessarily translate into higher industrial production costs. Further, despite earlier concerns, the facts show that price liberalization in Mongolia during the last 2-3 years has not caused lasting inflationary repercussions. Indeed, the immediate danger is not that price increases will be inflationary but rather that electricity price increases will be insufficient if prices are not indexed to inflation and therefore maintained in real terms. Coal Prices 19. Coal prices for major mines in 1994 were not far from rough estimates of the economic costs of supply through the 1 990s. However, price levels must be adjusted every year to account for inflation or any currency devaluation, to avoid major departure from economic costs. Major reforms are needed in the way in which prices are set, moving away from government-set prices to market-driven prices in long-term contracts negotiated between mines and consumers. While there may be a need for some continued government price regulation in the few cases where market forces are insufficient, such price regulation should be based on well defined mechanisms that provide incentive for efficiency to coal producers while adjusting for inflation. Petroleum Prices 20. Average petroleum product prices are based on international prices, and, on average, equal or exceed economic costs. However, there is a need to make price adjustments derived from international price variations less bureaucratic and more automatic. The current uniform pricing system, whereby consumers are charged the same prices regardless of their location, also should be reformed so that consumers in low cost distribution areas pay less and consumers in high cost areas pay more. 2 "Ecuador: Energy Pricing, Subsidies and Interfuel Substituion" ESMAP Report No. II 798-EC - vii - Debt and Arrears 21. The cash flow of the energy companies--particularly CES, the coal mines and NIC--is now seriously strangled by reciprocal high accounts receivable and accounts payable. In the short-term, the high level of accounts receivable--mainly from CES--is the most serious financial problem facing the coal companies. This is not a transitory problem but a structural one requiring energy tariff adjustments in electricity and heat. At the end of 1994, Baga Nuur Coal Company's (BNCC) account receivable from CES amounted to US$ 9 million equivalent, or about seven months of sales. During the January-May period of 1995, BNCC had been paid for less than 1/3 of the coal delivered to the power plants. 22. To address this issue, two types of actions are required. First, there is no choice but to dramatically tighten payment policies for future deliveries. It must be made clear to intermediate and final consumers that lack of payment will, from now on, result in suspension of supply. For the case of CES in particular, there is now only one choice if the Government is to avoid an impossibly high demand for direct financial transfers: further tariff adjustment and improved bill collection and enforcement. The central bank has performed economy-wide payments clearing operations, but debts piled up again because the underlying problem of tariff adjustments has remained unresolved. Restructuring Energy Companies 23. With pricing and bill collection reforms providing an improved operating environment, a final important reformn requirement is to restructure the energy companies to improve their efficiency, performnance and accountability. Company management will need to make a major transition from the previous focus on physical targets to a new focus on financial performance in a market environment. Conversion to international accounting standards is important to enable managers to have a complete and accurate picture of future internal financial requirements for investments in modemization/expansion, asset replacement and renewal, and servicing of increasing debt burdens. Internal financial management and reporting systems need to be revamped. 24. At the company level, this review recommends that the CES be divided into two fully independent commercial entities, separated from both MEGM and each other. One company would be charged with responsibilities for power and heat generation and power transmission and distribution in CES's current system. A second company (or, preferably, group of companies) would be charged with responsibility for district heating. Bulk heat should be provided by the electric power company to the district heating companies according to a long term contract, covering the full cost of heat production. Any government transfers for any consumer heat price subsidies should be provided through the district heating companies, and should not involve the electric power company. - viii - 25. In the coal sector, full responsibilities for coal mine operations and management should be given directly to the coal mining companies concerned. The EUOs also should be granted greater independence to operate as commercial entities, but they will need special assistance in manpower development and training to function properly. Although further efforts are required, institutional reforms in the petroleum product distribution system already are moving in a sound direction. Investment Priorities 26. Table 2 below provides an outline of priority investment needs in the energy sector (excluding upstream petroleum) during the next five years. These investments focus on: a) improving firm capacity, reliability and quality in the coal- power-heat delivery system, hence increasing security of supply in the power/heating sector; b) reducing losses in the district heating system; and c) diversifying petroleum supply arrangements. These investments must be accompanied by sector reforms aimed at separating the policy and operational roles in Government; converting the energy companies into commercial enterprises, including improved bill collection and tariff adjustments; and creating the regulatory reforms to attract private investment for new large investments in expansion and modernization of the energy sector. Table 2: Investment Priorities in the Energy Sector (Next 5 Years) US$ Millions Coal Sector Mine Rehabilitation 55 - 85 Combined Heat and Power DH Rehabilitation 37 - 45 Variable Flow Conversion 40 - 50 CHP Plants No. 3 & No. 4 Rehab. 110 - 130 Other CHP plants 5 - 10 Downstream Petroleum Transshipment Facility 10 - 15 Total Financial Requirements 257 - 335 Source: Mission Estimates. 27. The priority investments in Table 2 are in tune with current estimates in the indicative public investment program for the 1994-97 period, averaging US$47 million per year. Additionally, about a third of these investments are being financed, or are under consideration, by the ADB, donor countries and the World Bank. - ix - Coal 28. The first priority for substantial investment in coal mining is to rehabilitate and modernize the Baga Nuur mine, which currently accounts for about one-half of national coal production. A total of some US$45-55 million is needed to return the mine to its original production level of 4 million tons per year. Investments are needed to completely remove the current railroad overburden haulage system and move to a more efficient dragline, truck and shovel operation, and to construct a new coal handling facility to help improve coal quality. Additional important investments include (a) modest investments at Sharyn Gol mine (US$5-10 million), to maintain production for key consumers during the next five years, (b) investment in a coal handling plant at Shivee Ovoo (US$5-10 million), and (c) investigation, followed by any necessary investment, of additional remedial actions to improve coal quality at Shivee Ovoo. CHP Plants and Future Power Expansion 29. Thefirst priority is to proceed with the rehabilitation of power plants # 3 and #4 to improve reliability, instrumentation and controls, and reduce forced outages. A total of US$110-135 million will be required, of which the ADB and the Government of Japan are financing US$80 million. A second and almost parallel priority is to evaluate at the pre-feasibility level the conversion of the district heating system to a variable flow, the partial replacement of the network, and needed repairs and maintenance in the district heating system. The results of an evaluation on conversion to variable flow would modify the timing and composition of the power expansion plan. However, even after rehabilitating the CHP plants, the power system will still have reliability problems in facing peak load and regulating the system to random fluctuations in frequency and voltage. Hence, a third priority is, in light of the results of the Master Plan, is to undertake new investments, with maximium private sector participation. District Heating 30. Investment in rehabilitation and modernization of district heating systems are needed both to avoid further deterioration in heat supply and to improve CHP plant and power system operations. In addition to routine maintenance and repairs, priority investments for the next two years for the Ulaan Bataar system total about US$12-15 million, for improved insulation, measures to reduce water leakage, replacement of some branch lines and improvements in the secondary system. A next level of importance is to convert the system from constant to variable flow, to enable the system to meet actual consumer demand, to enable proper load management, and to allow introduction of end- user demand management. Conversion to variable flow would provide a reduction in heat peak load of at least 30 percent, and could be implemented in the Ulaan Bataar system at an estimated cost of about US$40-50 million. The final category of medium- term investment needed for the Ulaan Bataar system is for replacement of certain aging parts of the system (US$25-30 million). - x - Outlying Districts of Mongolia: Isolated Systems 31. Investment requirements in the isolated systems to stabilize production in the isolated energy systems are not particularly large, but small-scale investments to conduct renovations and repairs are critically important in some cases. The strategy should include the following elements: * over the near-term: - efficiency improvements in the use of diesel and coal for electricity and heat; - institutional strengthening through manpower development and performance monitoring; and - financial and managerial autonomy to allow EUOs to operate as commercial enterprises. * over the medium-term, to conduct a detailed evaluation on the economic opportunities for using renewable energy sources. Downstream Petroleum Operations 32. The Government's efforts in downstream operations are driven by the need to ensure continuity of supply. Therefore, to achieve this objective it is necessary to look at both least-cost and security of supply as the key variables. One project is construction of a transshipment facility at the Chinese border. This facility is needed to diversify supplies, however, its evaluation should include an assessment under the following scenarios: a) supplies from Achinsk versus other sources in terms of landed cost; b) merits of risk diversification, taking account of the cost of rationing in case of disruption of supplies; and c) alternative financing options to attract private capital. It is estimated that funding needs for construction of the bulk terminals would be about US$10-15 million. Next Steps and International Assistance 33. Just as the past five years were critical to steer the energy sector away from collapse, the next four years are going to be critical to position the sector on a path of financial self-sufficiency, reliable and efficient supply of energy with modern infrastructure, and minimum Government transfers to the sector. However to achieve these objectives the Government's focus, and hence international assistance, should be anchored around four basic milestones that would give Mongolia the flexibility to rapidly adapt to changes in both Mongolia's energy sector and in neighboring countries' energy sectors. In order of priority, these principles and corresponding actions (Table 3) are: - xi - * Stabilize and improve quality of coal, heat and electricity through rehabilitation of current facilities; * Transform the structure of the sector to a commercial nature, including radical tariff reform and improved bill collection.; * Build up the human resource capacity on policy making, regulatory activities and operation of commercial energy utilities and * Create the regulatory framework that would allow the sector to modernize its current infrastructure with maximum foreign and local private capital. Table 3: Indicative Action Plan in the Energy Sector OBJECrIVE ACTION TIME PERIOD Achieve financial self- sufficiency - Adjust tariff system and clear arrears. 1995-98 Improve Management of energy utilities - Establish energy utilities as commercial entities; - Establish purchasing contracts 1994-2000 Stabilize and improve quality of coal. - Rehabilitation of Baga Nuur mine. 1995-1998 - Improve quality of Shivee Ovoo and modest investment in Sharyn Gol Improve the firm capacity and reliability of - Rehabilitation of CUP plants; 1995-2000 CHP system. - Rehabilitation of DH piping system Optimize petroleum supply arrangements. - Diversify supply sources; 1995-1997 - Improve quality of products; - Remove uniform pricing system. Optimize operation of the CHP system. - Improve dispatch of CHP system; 1995-1996. - Evaluate feasibility of conversion of DH system to variable flow and impact on power expansion plan; Reduce losses in DH system. - Implement results of feasibility study including 1997-2000 efficiency program; Improve firn capacity in isolated systems. - Design and implement efficiency program. 1996-1999. Provide adequate environment to attract - Review and implement new regulatory framework, 1995- 1998. private capital to modemize infrastructure. including training of local staff on regulation of new market structure. I Energy Sector Overview 1.1 This chapter provides an overview of the energy sector, focusing on three areas: (a) linkages between macroeconomic developments and the energy sector; (b) an overview of the energy sector; and (c) current institutional and legal framework. Economic Adjustment and Sector Reform 1.2 With an area of 1.6 million square kilometers, Mongolia is a land-locked country between China and Russia with a population of about 2.25 million. Per capita GDP is approximately $ 320. The capital city, Ulaanbaatar, is the population center of the country with about 600,000 inhabitants. The second largest city, Darkhan, is much smaller with a population of about 90,000. 1.3 Although GDP contracted by almost 10% in 1991, the country experienced real growth of 2.4% in 1994 and should continue growing in 1995. Mongolian commitment to change is reflected in its efforts at stabilization and economic reform. Inflation is projected to be 40% in 1995 and has decreased from a peak of 420% in 1993. The current account deficit dropped from $1.2 billion in 1989 to $38 billion in 1993. 1.4 Given the pace of change, it is not surprising that Mongolia continues to suffer from the effects of massive dislocations and disruptions to the economy caused by the withdrawal of aid from the former Soviet Union and the transition to a market-oriented system. This is especially true in the energy sector. 1.5 Energy investments account for about 35% of public investments (Table 1.1). This proportion could change to 40-45% in the next 10 years. Based on experience in other countries the combination of financial transfers from the central government (2% of - 2 - GDP) and implicit subsidies in the pricing structure (12% of GDP)3 will undermine efforts to stabilize the economy, further decapitalize the energy companies and may eventually lead to larger transfers from the central budget. Table 1.1: Economic & Energy Linkages, Main Indicators Indicator Remarks Energy investment as % of public investment Currently 35%; about 40-45% over the next 10 years Financial transfers Currently Tug. 4 billion (2% of GDP); budgeted at Tug. 5.4 billion in 1995 Inter-company arrears Tug. 15.3 billion as of November 1994; 23% of current expenditure Subsidies $38 million for electricity tariff subsidies (about 8% of GDP). Source: Mission Estimates; "Mongolia: Country Economic Memorandum". 1.6 Total subsidies for heat and electricity amounted to approximately $50 million for public and residential use in 1993. Tariff adjustment should be addressed immediately to avoid increasing the level subsidies and the continued decapitalization of the CES. If Mongolia is to achieve reliable and efficient operations in this sector they must build institutional capacity at the policy and company levels, commercialize and modernize the nature of CES' operations and develop and implement a legal framework that will attract private investment for future sector growth. 1.7 As in other countries, the GOM's rationale for maintaining energy subsidies is to protect its poorest consumers. However, surveys by the State Statistical Office indicate that heating prices paid by the poorest groups, those living in gers4, are 5 times higher (Tug. 2,500 per month) than those paid by apartment dwellers. Further, based on the same surveys, electricity expenditures account for only 3.8% of total expenditures per household. An increase, in 1996, of 15% in real terms would represent additional expenditures of Tug 96/month for those households consuming 50 Kwh/month. The bulk of increases would fall on the industrial sector, the largest consumer of electricity. The focus of heating reform should be reduction of losses, metering of consumption, improvement of quality of service and gradual tariff adjustment. 3 The estimated levels of marginal cost for electricity and heat need to be further refined when the Energy Master Plan is completed. For now, these provide a good indication of tariff increases needed in electricity (60% of MC) and heat (30-33% of MC). 4 Traditional Mongolian tents with a coal-fired furnace in the middle of the tent. The furnace is used for both space heating and cooking. It was found that some gers located in areas where electricity is available, also used electric stoves. - 3 - Overview of the Energy Sector 1.8 In 1994, the coal mines were unable to supply sufficient quantities and qualities of coal to the power sector because of frequent equipment failure, production quotas resulting in slow overburden removal and poor manpower management skills. The coal arrives at the power plants mixed with rocks and other assorted objects, and accidents have caused coal piles to shrink to dangerous levels of 2-3 days supply at the power plants. 1.9 The power sector, in turn, is highly dependent on emergency donor assistance for spare parts and maintenance. Even with foreign aid, electricity and heat supply have been unreliable. Rolling black outs are scheduled throughout the year and it is common for unscheduled blackouts to occur at least once a week for a few hours in the Spring. This seems to be the worst time of year as coal and fuel oil (mazut) are in short supply after the long winter. 1.10 Early this year, Russia cut off its fuel oil exports to all countries due to shortages within Russia itself. Supplies of petroleum products in general (not only mazut) are constrained by the ability of Mongolia to secure long-term contracts with Russia. Given this evidence it is clear that Mongolia must improve efficiency in the operation of the energy sector and diversify suppliers. 1.11 Perhaps most dangerous of all is the erratic supply of heat. The district heating systems are hugely inefficient resulting in up to 40% heat and water losses. Demand Issues 1.12 The energy balance for 1993 highlights four main points (Annex 1, Table 1): * Coal is the main energy source and heat supply is the main energy use, accounting for close to 40% of gross energy consumption. * Mongolia's power system does not have the capacity to follow load fluctuations and meet peak demand in daily system operations. The Combined Heat and Power system (CHP) is highly inefficient compared to systems elsewhere, with conversion losses and station use of over 20%. Heat transmission losses are in the 35-40% range (exceeding the heat demand of the industrial sector). The industrial sector is the main consumer of power, accounting for about 70% of demand. The household sector accounts for almost 60% of heat demand, followed by industry with almost 30% (Figure 1.1). Figure 1.1: Energy Consumption by Sector- 1993 120 100 heat 80 heat 0) c 60 a-~~~~ca 20~~~~~~~~~~~~~0 coal SU)~~~~~~oa 0 1-- i--- ---- -_ Pbw er Industry Household & Other Sector Source: MEGM, mission estimates. Consumer Profile 1.13 Industry and Construction. As the backbone of Mongolia's economy, this sector is also its largest energy consumer. Industry and construction consumes about 14% of coal supplied, about 70% of electricity supply and 28% of heat produced. The country's industrial sector is characterized by a small number of relatively large production enterprises. Most notable is Erdenet Copper Mine which contributes to around 50% of the country's foreign exchange earnings and accounts for about 36% of electricity consumption (Gwh) and about 15% of peak power demand. Expected increases in future energy demand will remain low even though industrial growth is expected range from 2-3.5% per year. 1.14 Transport and Communication. This sector essentially uses petroleum and a small amount of electricity (about 4%), consumed by the electric powered public trolley-bus system in Ulaanbaatar. For road transport, the majority of freight trucks and even public buses are gasoline fueled leading to a proportion of gasoline vs. diesel consumption of 82:18. Due to increasing diversification of transport vehicles in Mongolia, the number of diesel fueled vehicles is increasing. - 5 - 1.15 Agriculture. The agriculture sector is the smallest energy consumer, accounting for less that 4% of total end-use energy consumption. This situation is expected to remain unchanged in the future. 1.16 Communal Housing and Public Services. This sector is the second largest consumer of energy in the country. It accounts for 2% of coal, 58% of heat and about 16% of electricity demand. Public services include government offices and buildings, schools, hospitals, and other non-commercial facilities owned by the government. Communal housing includes multi-storied apartment buildings, and some single family homes and gers located in or near the urban centers. Most of the buildings, particularly in Ulaanbaatar, were constructed after World War II. These buildings have higher energy consumption levels compared to older ones. The newer buildings were constructed in a manner that limits the flexibility of inhabitants to control their individual energy consumption leading to over-consumption of heat. 1.17 Energy costs differ across the country. Consumers in rural areas pay as much as three to four times more for coal than urban consumers. Power generation is usually more expensive due to sparseness of population and fuel transport costs 1.18 Given variable pricing situation some interfuel substitution is occurring in the residential sector although specific quantities have not been determined. For example, in the ger district around Ulaanbaatar, people have switched to electric cooking stoves or are using fuelwood instead of coal in their furnaces. This shift away from coal could be due to the unsubsidized and therefore high real cost of coal in certain areas. Also, due to insufficient quantities of hot water provided by district heating systems, some single family homes have invested in small-scale, sometimes crude, coal-fired boilers and water pumps to meet their hot water and space heating needs. Reliability of Meeting Future Energy Demand 1.19 The evidence presented in this report and the past record of the energy system shows it would be a challenge to meet future energy demand in a reliable manner. As it is, the energy system, particularly the CHP system, could suffer a catastrophic failure at any moment. Already, heat demand during the winter cannot be met from the current system. 1.20 For the future, conservatively,5 end-use consumption of energy will grow at an average rate of slightly more than 2% per annum to the year 2000. The highest growth will be in the transport and communication sectors at 3.7% per year. 5 GDP growth (%): 1994 = 2.3; 1995 = 2.6; 1996 = 3.0; 1997 and beyond = 3.5. - 6 - 1.21 Energy consumption in industry and construction is estimated to grow at approximately 2.5% a year until the year 2000. This assumes that more cost-reflective energy prices will be phased-in and that additional investments in equipment will be of the more-modem and energy-efficient type. Consumption in communal housing and public service will follow population growth, although at the slower pace of less than 2% per year. In agriculture, energy consumption is expected to decrease. 1.22 As a result, total energy requirements for Mongolia could reach about 2.5 mtoe by the turn of the century, up from 2.2 mtoe today. Coal production will need to reach 2 million toe per year. This is an increase of 0.7 million tons per year, or 14% compared to 1993's production level. Gross generation of electricity will need to increase by 35% and heat by 18% over this period. Requirements for gasoline will increase by 38% and 9% for diesel. Demand will remain constant or increase slightly from the suppressed consumption levels of 1994 (Annex 1). To position the sector to support these conservative growth levels, reforms will be required in the institutional and regulatory framework. Institutional and Regulatory Framework Institutional Framework 1.23 The sectoral institutional structure has the fcllowing characteristics: government ownership and control of all aspects of supply, distribution and pricing of energy sources. Institutionally, the largest coal mines (Baga Nuur, Sharyn Gol and Shivee Ovoo), CES-- in charge of the CHP system and rural energy companies-- and the Mongolian Petroleum Company (MGT) are accountable to the MEGM. The Ministry of Trade and Industry (MTI) oversees downstream petroleum operations through the Neft Import Concern (NIC). institutional concentration of generation, transmission and distribution of energy supply operations, particularly for CHP (there is only one company), thus limiting the participation of other state/private enterprises. * lack of human resources with experience in the design and coordination of energy policies in a market environment, and in the management of commercial energy enterprises. 1.24 As an example, Figure 1.2 below shows the current institutional framework of the CES vis-a-vis the MEGM. - 7 - Figure 1.2: CHP System- Current Institutional Structure Economic Cabinet MEGM Energy Board | CES Head Office r- - - - -- - - -- - - -- - - - -- -- -- -- - -- - - --, CHP Plant No 2 Electricity Heat Others: I CHP Plant No. 4 Choir Energ Center EDarhan CHP Plant Organizations Organizations | D Resagn rc Center DErhene CHP Plant DsrbtoDirbuonCiReneargy Center l Other Power Plants Repair Factory l Training Center Resthouses 31 Enterprises - - - - - - - - - - - - - - - -. - - - - - - - - - - - - - - - 1.25 The current institutional framework merges policy and management roles causing confusion and lack of accountability. MEGM is in charge of both the management of the CHP system and sector policy. Further, the involvement of MTI in downstream petroleum sector responsibilities has mixed policy and operations. Experience in other countries has shown the benefits of separate roles for policy making, regulation of the sector and management of the energy companies. 1.26 Suggested responsibilities for MEGM include: (a) energy sector policy and development strategy; (b) licensing and supervision of operational regulations, such as safety or health requirements; (c) promotion of sector investments, including coordination of international aid; (d) coordination of industry activities and representation of the industry at the Government level; and (e) monitoring fuel stocks in the country and control over imports and exports of energy if there are genuine national security concerns. Regulatory responsibilities are discussed below. Regulatory Framework 1.27 There are three main legal instruments in place to legislate energy sector operations: a) the Mining law; b) the Petroleum Law, which focuses on up-stream petroleum operations; and c) Decree 224, which governs CES operations vis-a-vis the MEGM. Additionally, a draft Energy Law under preparation focuses on power sector - 8 - and district heating regulation. In this review we have studied the draft Energy Law and decree 224. 1.28 Decree 224 and the draft energy law together provide a good start to restructure the power and district heating system. As currently proposed, the Energy Law seeks to regulate the generation, transmission, and distribution of energy (electricity and heat). This includes an institutional framework for government roles at the central and local levels as well as private sector participation; the establishment of a regulatory agency; granting of permits; determination of tariffs; safety standards; and arbitration. In its current form, the draft energy law provides the following structure to the sector. Figure 1.3: Proposed Institutional Structure under the Draft Energy Law Generator Generator Generator Bulk Energy Buyer | ~~~~Distributor| | Heat l l Electricity | 1.29 Subject to removal of certain articles that perpetuate the GOM's policy, regulatory and management roles, the draft Energy Law provides a very advanced regulatory and institutional framework for which Mongolia may not have the tools and experience to operate. For example, in Figure 1.3, the bulk energy buyer in the CHP system may require investment capital of about $20 million to upgrade the dispatch center. 1.30 As a next step it is necessary to review and complete the Energy Law bearing in mind the following principles: (a) the law should allow any person to enter, operate and exit the market under proper licensing procedures, giving equal treatment to private and public companies; and (b) the law should explicitly separate the policy functions (para. 1.26) from the regulatory functions (para 1.31) and management functions of the energy enterprises. In an initial stage, and given the need to train staff on regulatory aspects of the energy industry, there may be a need to work through performance contracts between the energy companies and the main shareholder, the Government. 1.31 Some of the suggested duties to fall under regulation of the sector include: (a) set procedures and set tariffs on those activities considered natural monopolies; (b) issue - 9 - and enforce licenses and/or concessions to operators; (c) provide advice and information to Ministry; and (d) arbitrate between operators. Some of these functions are suggested under the current draft Energy Law through a proposed "Central Organ". However, it still mixes policy and regulatory functions. 1.32 At the level of CES, Decree 224 establishes CES as a holding company, managing their operations through performance contracts with its subsidiaries. However, in the absence of reliable financial figures and indicators those performance contracts have lost their meaning. Further, there is little purpose to establish contracts with CES if this is not preceded by a restructuring of CES, including the divestiture of their non-core activities. 1.33 In the coal sub-sector the current institutional framework also lends itself to the conflict of interest between policy maker and mine manager. Under the current structure, the mines have no role as commercial entities, for the MEGM allocates coal supplies to the CHP plants, it decides upon inter-company arrears and Nuurs, a state- owned wholesale company, is also responsible for procurement on behalf of the large coal mines. Figure 1.4: Current Institutional Framework in the Coal Sub-sector Large Coal Mines: Baga Nuur Sharyn Gol Sivee Ovoo k CHP Plants NLJURS Small Consumers in the Medium & Small Consumers Rural Areas 1.34 Elements for Reform. The first step in the institutional and regulatory reform of the CES, and the coal companies in particular, should be the separation of MEGM's policy and management/operational roles. As an interim step, they should be replaced by drafting new performance contracts, establishment of financial and management systems at selected enterprises and financial and management restructuring of the CES, including divestiture of non-core activities. This legislation could be - 10- supported following review and modifications to ensure the separation of policy and management roles. Along those lines, the ADB is preparing terms of reference to review, modify and assist in the implementation of a new regulatory and institutional framework. 1.35 This report shows that it is possible to improve cash generating capacity, rehabilitate and initiate modernization of the physical and management infrastructure, and improve the reliability and quality of energy supply. However, these can be achieved Qnly if the GOM commercializes the operations of energy companies, adjusts tariffs gradually but consistently, reinforces its own institutional and management capacity; and modifies its legal framework to entice private sector investment. Without competitive private sector participation, it is highly unlikely that the GOM will be able to bring in the required new investments to modernize its infrastructure and management skills. - 11 - 2 Coal Sector Exploiting its Main Indigenous Energy Resource 2.1 Mongolia's existing mines clearly have the reserves and production potential to cost-effectively meet the country's major coal needs into the next century. The challenge for the industry is to stabilize and then gradually increase production, and to meet the quality requirements of customers while minimizing cost. Thus, the priority actions include: * rehabilitation of the Baga Nuur mine to return to a production level of at least 4 million tons per year; * modest investments in Sharyn Gol mine, to maintain short-term production; and * further investment in Shivee Ovoo mine, to allow it to reach its design capacity and improve coal quality. Reserves, Production, and Demand 2.2 Coal mining in Mongolia dates back to the early 1900s. Open-pit coal mining now provides about 80% of the country's energy supply. Mongolia possesses substantial reserves of coal, estimated at over 2.5 billion tons; this compares to average annual production of 5.5 million tons in the last 3 years. Reserves 2.3 Principal reserves of coal are located at the existing Baga Nuur and Shivee Ovoo open-pit mines (0.75 billion tons) to the east and south, respectively, of Ulaanbaatar, and at the undeveloped Tavan Tolgoi deposit in South Gobi (1.6 billion tons). The quality of Mongolian coal reserves covers the full range from lignite through bituminous and coking coals. The large-scale Baga Nuur, Sharyn Gol and Shivee Ovoo - 12 - mines, produce lignitic coals with heating values of 2,700-4,000 kcal/kg, 18-35% moisture and 12-21% ash. Smaller mines range from similar lignitic qualities up to higher 5,000 kcal/kg quality, low moisture bituminous coals. Tavan Tolgoi coals, although essentially undeveloped at this time, are extremely high quality (8,000 kcal/kg, 8.5% moisture and 20% ash) by any international standard, and approximately 50% of these reserves are classified as excellent coking coals. All coals in Mongolia are low sulphur (less than 1%), except Shivee Ovoo (1.5%). Production 2.4 There are 16 operating coal mines in Mongolia: three large-scale open-pit mines at Baga Nuur, Sharyn Gol and Shivee Ovoo; one medium scale (0.6 million tons per year or mtpy) operation at Aduunchuluun in eastern Mongolia, and 12 smaller scale (less than 0.25 mtpy), local "aimag" coal mines, all but one of which are open-pit operations. Table 2.1: Coal Production, 1980-1994 Mine 1980 1988 1989 1990 1991 1992 1993 1994 est. BagaNuur n.a. 4.1 3.8 3.7 3.8 3.4 2.8 2.9 Sharyn Gol n.a. 2.1 1.9 1.4 1.3 1.3 1.2 1.1 Shivee Ovoo n.a. - -- 0.1 0.5 n.a Nailakh n.a. 0.5 0.4 0.2 0.2 0.1 -- -- Other na 1.9 199 .9 1:7 1.5 1.0 n.a Total 4.4 8.6 8.0 7.2 7.0 6.4 5.5 n.a Source: MEGM; mission estimates. 2.5 With an original capacity of 4 mtpy and ample reserves of medium-quality lignite for production well into the next century, the Baga Nuur mine is the backbone of the sector. Production has dropped substantially during the 1990s, however, reaching only 70% of designed capacity in 1993 and 1994. Sharyn Gol produces the highest quality coal of the three large open-pit mines. Production at Sharyn Gol also has fallen substantially below the designed capacity of 1.5 mtpy. Shivee Ovoo is a new mine, where production has not yet met a designed capacity of 1.2 mtpy. Coal produced at Shivee Ovoo has been of particularly low quality so far. Demand 2.6 The three large coal mines provide all of the coal used by the five CHP plants of the CES, the country's main industries, and most of the small consumers in the main urban centers (see Table 2.2). The medium and small mines provide coal for local heat systems and other local consumers in the smaller towns. The CES is by far the largest consumer of coal, accounting for 65% of national coal use. Most of the coal provided to the CHP plants and other large consumers is supplied directly by the mines, - 13- based on agreed annual allocation plans established by MEGM. The state-owned Nuurs Company acts as a wholesale agent for many of the medium and smaller consumers in the main urban centers. Nuurs Company purchased and sold about 744,000 tons of Baga Nuur and Shivee Ovoo coal in 1993. Table 2.2: Coal Demand, 1993 ('000 tons) Baga Nuur Sharn Gol Shivee Ovoo Other iQal Ulaanbaatar CHP No. 2 82 57 2 -- 141 Ulaanbaatar CHP No. 3 362 555 14 -- 931 Ulaanbaatar CHP No. 4 1,750 -- 300 -- 2,050 Darhan CHP -- 214 -- -- 214 Erdenet CHP 76 130 6 21Z TOTAL CES 2,270 956 322 0 3548 Key industries 55 155 4 -- 214 Railways 81 5 -- -- 86 Other consumers 442 67 177 9Q7 1593 TOTAL 2,848 1,183 503 907 5441 Source: MEGM, adapted from IEEC's Coal Pricing Study 2.7 Baga Nuur mine supplies most of its coal to CES, especially CHP Plant No. 4 in Ulaanbaatar, the country's largest CHP plant. The higher quality Sharyn Gol coal is provided primarily to CHP Plant No. 3 in Ulaanbaatar, and the CHP plants in Dakhan and Erdenet, which were designed to use this coal. Key industries which also rely on this higher quality coal consumed 13% of Sharyn Gol's output in 1993. Shivee Ovoo coal is being used mainly at CHP Plant No. 4, with some additional sales to small consumers through the Nuurs Company. The low quality of the coal produced to date from Shivee Ovoo is a source of complaints from the CHP plant operators. 2.8 While there has been evidence of some shortages in coal supply during the winter months of 1993 and 1994, the extent and nature of true coal shortages are unclear, partly because coal is allocated by administrative means and not through a market. A matrix of targets for mine production and for supply levels to the main individual consumers is prepared by MEGM each year, in consultation with authorities from the mine, consumer and transport authorities. Neither targets for mine production nor targets for supply to many of the key consumers, particularly the CES, have been achieved in recent years. 2.9 Many consumers, including the CES, complain that they are unable to obtain timely deliveries of coal of the quality they require. Much of the problem, however, stems from poor stockpile management at the mines and CHP plants, poor scheduling of transportation and delivery, and uneven coal quality. Among small consumers, some degree of shortage is indicated by high black market prices for coal - 14 - supplied outside of regular channels, i.e. about Tug. 8,000-10,000/ton compared with Tug. 3,500/ton ex-stock yard in CES. 2.10 Given a review of coal needs for heat and power generation, coal demand will grow very modestly through the end of the decade. With some improvements in efficiency, coal requirements for heat and power production are expected to grow by only 10-15% between 1993 and 2000. Accordingly, total coal demand is not expected to exceed 7 million tons (averaging 3,500 kcal/kg) until after 2000. Pricing and Financial Situation of Coal Companies 2.11 The level of coal prices at the major mines is not the most pressing concern at this time. Minegate coal prices for the major mines in 1994 were not far from rough estimates of the economic costs of supply through the 1990s, in contrast to the situation for electric power and heat tariffs. However, accurate estimates of the economic costs of supply of the different mines, approximated by the average incremental cost (AIC) of additional production, will require further study, given current uncertainties in the current operating cost data, uncertainties concerning future operating costs, and difficulties in defining the future incremental production stream resulting from incremental investment. At Baga Nuur, the minegate price of Tug. 2,500/ton compares with AIC estimates of Tug. 2,400-3,200/ton. At Sharyn Gol, the minegate price of Tug. 3,500/ton compares reasonable well with AIC estimates of Tug. 3,200-4,000/ton for production over the next five years, but would be well below the AIC of supply from a high stripping ratio operation after that. While AIC estimates were not prepared for Shivee Ovoo, where the minegate price in 1994 of Tug. 2,200/ton was the lowest of the three, the incremental cost of increased supply from this mine is also expected to be low, unless the required measures to improve quality are particularly expensive. 2.12 For the future, average price levels, however, need to be adjusted regularly to account for inflation or any future currency devaluation, in order to avoid a big gap with economic cost of supply. Already in mid-1995, a significant gap was beginning to develop, due to lack of regular adjustments to domestic currency prices. 2.13 While 1994 prices may be close to estimated incremental production costs, revenues retained by coal companies are insufficient to provide a suitable contribution to future investment and equipment renewal. This is because depreciation, based on historically valued assets, is greatly underestimated, yielding relatively high "net profits" and, hence, funds for asset renewal are transferred to the state in the form of taxes. Based on planned figures for 1994, taxes owed by the Baga Nuur Coal Company amounted to over US$0.90/ton (15% of revenues). The tax shares of revenue at Sharyn Gol and Shivee Ovoo are slightly lower. - 15 - 2.14 In the short-term, the high level of accounts receivable--mainly from CES- -is the most serious financial problem facing the coal companies. This is not a transitory problem but a structural one. As of November 1994, accounts receivable totaled Tug. 5.2 billion, of which CES accounted for Tug. 3.7 billion (70%). In the case of Baga Nuur mine, arrears from CES had increased at the end of 1994 to a level equivalent to seven month of sales. 2.15 Consequently, coal companies have difficulties covering immediate operating expenditures, such as the monthly wage bill. As a result, in November 1994 coal company accounts payable totaled Tug. 4.3 billion, including Tug. 1.2 billion for equipment, Tug .8 billion for petroleum products, Tug. .5 billion to the railroad company an Tug. 1.8 billion to the State taxation commission. Priorities for the Coal Sector 2.16 Increasing the reliability and efficiency of coal supply in Mongolia will require investments in the rehabilitation of selected mines as well as implementing a comprehensive reform program. Production Prospects 2.17 The challenge for the industry is to stabilize and then gradually increase production, and to meet the quality requirements of customers while minimizing cost. The current and future relative roles of the three main mines are a key part of the picture, as the cost structure and quality of coal from each are quite different (see Table 2.3). Table 2.3: Coal Quality and Costs Estimated 1993 Production Average Calorific Avg. Incremental Design Capacity mlt Value Cost of production Mine (mtpm) (Kcal/kg) (US$/t) Baga Nuur 4.0 2.8 3200-3500 6-8 Sharyn Gol 1.5 1.1 3800-4000 8-10 (1995-99) 12-15 (2000 on) Shivee Ovoo 1.2 0.5 2200-2700(to date) n.a. 3300 (design) Source: MEGM and mission estimates 2.18 The Baga Nuur and Sharyn Gol mines were designed and equipped on the basis of Russian mining principles and technology. These two mines face serious development constraints including: (a) moving from a production-driven to a cost-driven mine planning strategy; and (b) replacement of the inflexible and high-cost rail - 16 - overburden removal systems and modernization of the main mining support equipment fleets. The mine plan and technology at the new Shivee Ovoo coal mine--developed by Mongolian planners without international assistance--appears both well engineered, and relatively well managed and operated. However, coal quality in the hydrogeological regime of the initial (outcrop) mining area is well below consumer specifications, rendering the present development of limited economic benefit. 2.19 Baga Nuur remains the key mine for the sector. With rehabilitation and improvements in efficiency, the mine has sufficient reserves to produce at its original capacity of 4 mtpy for six more decades, with an attractively low stripping ratio of 3.5 cubic meters of overburden per ton of coal. The average incremental costs of additional production from the mine are estimated by the mission at US$6-8/ton.6 The average calorific quality of the coal is sufficient for the Ulaanbaatar CHP Plant No. 4 and other consumers designed to use this coal, although improvements need to be made to make the quality of coal more uniform and consistent. Production could be increased beyond 4 mtpy, with no substantial increase in incremental costs, provided of course there is a market for the coal. 2.20 Although continued use of its higher quality coal will remain necessary over the short term, sustained future production at the older Sharyn Gol mine would involve very high stripping ratios, and costs per ton easily twice those at Baga Nuur. With modest rehabilitation investments, the mine could sustain production at about 1993 levels through the end of the decade; i.e., mining the most available coal deposits at a stripping ratio of 3:1 or less and an estimated average incremental cost of about US$8- 10/ton. By 2000, however, the mine would face stripping ratios of 6:1 or higher, and the much higher costs involved are likely to be unsustainable. However, a number of key consumer installations are designed to use the 3,800-4,000 kcal/kg coal produced by this mine, and substantial investments are required to adjust to lower quality coal. With assistance from the ADB, the Ulaanbaatar CHP Plant No. 3, which currently consumes about 50% of Sharyn Gol's output, is undertaking renovations that would enable a shift to Baga Nuur coal. 2.21 The future role of Shivee Ovoo depends upon the extent to which the mine can improve coal quality. Although costs at this mine were not reviewed, the fact that the mine has not yet reached design capacity suggests that average incremental costs should be relatively low, unless dewatering or other investments to improve quality prove to be particularly expensive. However, with calorific values of 2,200-2,700 kcal/kg so far, the coal produced to date cannot meet consumer needs. 6 Average costs per ton, including adjustments for proper asset depreciation, appear to be within the same range. - 17 - Mine Development Prospects 2.22 The priority is to focus on the rehabilitation of the Baga Nuur mine to ensure that production is returned to its original level. In parallel, modest investment to maintain short-term production at the Sharyn Gol mine is important to supplement the Baga Nuur production, although investments in long-term production at this mine are unlikely to be viable. In addition, investigations need to be undertaken at Shivee Ovoo to identify the specific nature of coal quality difficulties and remedial actions. Associated investment requirements are summarized and further discussed below. Table 2.4: Estimated Investment Requirements for Rehabilitation of Large Mines, 1995-97 US$ million Baga Nuur Mine rehabilitation 35-40 Coal handling plant 10-15 45-55 Sharyn Gol 5-10 Shivee Ovoo Coal handling plant 5-10 Other 0-10 TOTAL 55-85 2.23 Baga Nuur Mine. Mine rehabilitation at Baga Nuur is the first priority for substantial investment in the coal sector. The main operational and technological constraint at Baga Nuur is the serious limitation and high cost of the current system of removing overburden by rail haulage. The present rail haulage system on the upper overburden benches reaches only 40% operational efficiency, resulting in inadequate overburden removal, and thus there are shortfalls in coal release and production while yielding inefficiencies in simultaneous truck operations. Production and maintenance costs are also too high; at current productions levels, overburden removal by railroad is costing about US$1.10/bank cubic meter (bcm), compared to US$0.52/bcm for haulage trucks. Consequently, the top priority is complete dismantling of the rail overburden removal system, and replacing it with a mobile (truck/shovel) operation. 2.24 The rail system should be replaced by a combination of larger capacity 10- 15 cubic meter excavators and 85 ton trucks. Traditional mining systems at Baga Nuur use a combination of 4 cubic meter shovels and 35-40 ton trucks, but these units are too small in relation to the overburden quantities that must be moved. A shift to equipment produced outside of the former FSU/CMEA countries may also facilitate the exposure of personnel to present-day mining technology and may ease difficulties in procuring spare parts. - 18 - 2.25 Mine rehabilitation should also include purchase of appropriate fleets of bulldozers, graders and other auxiliary equipment to support mining operations and to help approach mining efficiency levels more typical of international operations. Some reconstruction work has taken place at Baga Nuur's coal handling facility, following a recent series of explosions. However, health and safety risks, as well as operational efficiency, remain unacceptable. Thus, the coal handling facility should be fully redesigned and reconstructed to improve worker safety and health, and to improve the quality and uniformity of Baga Nuur's coal supply to consumers.7 2.26 Investments to revamp mining methods and provide new equipment alone will not solve Baga Nuur's operational problems and raise production to capacity. Major improvements are required in mine management. The productivity of equipment is exceptionally poor; operating only at an average of six hours per twelve-hour shift. This is caused by extremely poor equipment maintenance practices and inadequate supervision at the mine. If equipment operation increased to an average of 8.4 hours per twelve-hour shift, this would result in production roughly equivalent to a 40% increase in the size of equipment fleet. 2.27 Sharyn Gol Mine. Continued production at Sharyn Gol over the medium and long term is unlikely to be financially or economically viable. If the mine focuses on production of relatively accessible coal during the next five years, production costs should be competitive with Baga Nuur on a calorific basis. Long-term production, however, will entail much higher costs for overburden removal. The key issue is the extent to which consumers will be willing to pay much higher prices for the higher quality of Sharyn Gol's coal, or whether they would prefer to make adjustments and use lower quality coal from Baga Nuur or Shivee Ovoo. 2.28 The Sharyn Gol Mine should put its immediate attention to efficient mining of coal that can be removed with a stripping ratio of 3:1 or less. Unless the domestic market confirms strong demand for the mine's coal at much higher prices, overburden removal for the long term should be curtailed, and all new investment at Sharyn Gol must be for short-term production. For purchase of new equipment, careful consideration should be given to the feasibility of redeploying such equipment to other mines midway through their useful life. In this way, although the 1.5 mtpy design capacity is not likely to be reached again, it may be possible to maintain production through thc caid of the century at an economically attractive cost. 2.29 In parallel, the current system of fixed prices for the mine's coal should be phased out, and prices should be allowed to float upwards, based on demand. The CES and key industrial consumers must be made aware that Sharyn Gol coal can only be made available over the longer-term at minegate prices in the US$12-15/ton range (Tug. 5,000- 7 Poor coal quality is estimated to account for over 50% of the outages at CHP Plant No. 4. - 19 - 6,000/ton, in 1994 terms) or higher. This is at least 40-70% more than 1994 prices. If consumers find it more attractive to make adjustments and use other coals, there is enough time at this point for a smooth transition. 2.30 Shivee Ovoo Mine. The new mine at Shivee Ovoo is well engineered and planned, being equipped with western style truck-shovel combinations, and it appears to be well managed. Although it was planned to produce coal of 3,300 kcal/kg quality, the initial mine cut is presently delivering coal only in the 2,200-2,700 kcal/kg range due to: (a) the mine opening on the outcrop is excavating oxidized coal of low quality; and (b) there appears to be a hydrogeological regime yielding coal of higher moisture content than anticipated during exploration. Mine management indicated that these can be resolved during 1995 and that thereafter, coal of satisfactory quality can be produced. The geological/hydrogeological regime warrants further investigation to identify the timing and quantities of coal production that can meet quality specifications. In addition, coal is presently loaded directly into rail cars without any sorting and sizing. This is not acceptable to any consumer and a simple coal handling facility needs to be built. 2.31 Without resolution of the quality issue, there is no demand for this coal. Currently, mazut (a low-quality fuel oil) must be added to maintain proper combustion at the CHP plants. The current minegate price of Tug. 2,200/ton (US$5.50/ton) would be very competitive if a calorific value of 3,200 or 3,300 kcal/kg could be maintained, and no mazut were required. However, the additional cost of fuel oil raises the effective cost of coal to unacceptable levels--reaching over Tug. 6,000 (US$15) per ton at 2,700 kcal/kg and almost Tug. 10,000 (US$25) per ton at 2,200 kcal/kg.8 2.32 Tavan Tolgoi Coal Area. Although infrastructure development requirements would be substantial, there is good potential for development of large, high- quality coal reserves in the Tavan Tolgoi area, in the Gobi Desert. Presently, only a small aimag coal mine is operating in the area for use in local heating plants. However, in a series exploration activities and feasibility studies during 1945-1985, Russian specialists identified huge coal reserves with low stripping ratios in this area, with prospects for development of a 20 mtpy thermal and coking coal mining operation. The thermal coal seams are reported as exceptionally high quality (8,000 kcal/kg), as are the coking coal reserves, although the Russian determinations of coking properties are not easily comparable with international testing parameters and specifications. From a mining point of view, at least, there are very promising long-term prospects for development on a large scale through private sector financing. 2.33 The mine could both supply Mongolia's thermal coal requirements and provide exports of thermal and coking coal to Russia and/or China, or, through these countries, to other international markets. International experts should assist MEGM to 8 See JEEC, "Energy/Coal Pricing Study," p. 5-12. -20 - undertake further review of the Russian evaluations completed in the past (including further sampling and testing of the thermal and coking coal qualities), and to complete a preliminary assessment of infrastructure (transport) needs, options, and costs. Sector Reforms 2.34 As stated before, investments alone will not stabilize Mongolia's coal production; sector and mine management must also be improved. The existing ineffective sector and mine management system is the principal cause of the coal sector's poor performance. While new investment may yield some gains for 1-2 years, inefficient operating practices, poor equipment productivity and maintenance, and lack of cost control can be expected to negate any gains over the medium-term. To improve efficiency, the critical areas for system reform at this time include: * separation of coal companies from the government; * development of coal companies into commercial enterprises; and * development of market forces in the sector, including reform of the coal pricing system. 2.35 Separation of Coal Companies from the GOM. MEGM is heavily involved in the day-to-day management of the main mines, and the responsibilities of MEGM and mine management are intertwined and indistinct. Mine production targets and allocations to each major consumer are planned by MEGM each year, based on the inputs of the various parties involved. 2.36 Mongolia's coal companies need to be established as independent commercial entities, fully separate from MEGM, to provide incentives to and instill accountability for mine management to improve its operations. Mine managers must be fully accountable for the technical and financial performance of the mines. This requires that mine managers be given full authority over all operational and financial decisions in managing the mines. 2.37 The eventual goal would be to create an explicit and transparent system of mine company ownership, corporate management and government regulation, conducive to a market economy. Where private ownership is feasible, ownership and management may be combined within one private entity, and the government's role should focus on regulation. Where public ownership is retained, the management, ownership and regulatory roles must be clearly separated between different entities. 2.38 The GOM should proceed immediately with a basic separation of the coal companies from MEGM, despite parallel needs for regulatory and legal reforms. There is no need to await the outcome of broader initiatives; the coal industry should be allowed to increase its productivity and efficiency through this reform as soon as possible. The - 21 - first step, which can be completed in a few months, is to clearly define the functions of MEGM in the sector and the functions of the coal companies, followed as quickly as possible by implementation. 2.39 Responsibilities for the mining companies include: (a) authority over all mine operational matters, including labor issues in accordance with the law; (b) full responsibility and accountability for company financial management and performance; (c) coal marketing and sales contracting; and (d) preparation of mine development, investment and business plans, and their implementation under established guidelines. 2.40 Financial performance targets should be established for each mining company, to which company managers will be held accountable. Definition of these targets, and their supervision, should be undertaken by the company owners. Where the state is the sole owner, the state should be represented by an agency other than MEGM, to avoid conflict of interest with MEGM's policy making and regulatory functions. 2.41 As development of a suitable legal and regulatory framework proceeds, opportunities for privatization in the coal industry should be utilized. Earlier privatization vouchers, amounting to about one quarter of the company's estimated asset value, were distributed to employees at Baga Nuur, but without more fundamental reforms, this has had little meaning. With regulatory reform and progress in building the companies into proper businesses, however, meaningful privatization could bring benefits of capital injection and efficiency gains. Where public ownership is retained, the coal companies should be formed into corporations, based on evolving legislation to clarify public corporation ownership and governance issues. 2.42 Improving Coal Company Management. Especially under a regime of greater autonomy and accountability, min.e company management needs to be greatly improved. The goal is to improve cost-consciousness and to begin to manage mining companies as businesses. Priority areas include: * Development of corporate management capabilities. Companies need to develop their capacities for commercial management, including improved capabilities for legal, contractual, financial management and planning, cost monitoring and control, as well as executive leadership. In most cases, this will require staff with suitable qualifications and experience, as well as training. * Restructuring and strengthening of financial management and accounting practices. Operating as a business means that good overall financial performance is the key objective of the companies. Financial management now focuses purely on the recording of costs. The present system needs to be completely overhauled, including conversion to international accounting methods and development of financial reporting systems and - 22 - procedures that can be used as effective management tools to monitor and control costs. Improvement in organization and practices for supervision of mine operations. Management of supervision and coordination of the various mining sub-systems and equipment fleets needs to be reorganized to enable equipment and labor productivity to improved. Organization and management of maintenance facilities and functions must be upgraded to assure adequate equipment fleet performance. Labor discipline is a serious issue in Mongolian coal mines and would need to be addressed as a matter of priority by new management teams. The formulation of clear work plans, shift disciplines and labor performance expectations is critical for effective work force utilization. 2.43 Price Reform and Development of Market Forces. The main problems in the pricing and allocation system are (a) insufficient retention by coal mine companies of funds for investment, (b) the absence of market forces in the system, and (c) payment difficulties. 2.44 The consumers should determine the best production mix of coals of widely varying qualities and costs, by indicating how much they are willing to pay for each type of coal. The actual overall coal demand in Mongolia remains speculative, let alone demand levels for different varieties with different costs. Consequently, the GOM should take the necessary measures to abrogate its role in determining production and coal allocation targets, and to transfer this role to the mines and consumers directly, based on market principles. The goal should be to allow consumers to negotiate directly with coal suppliers. 2.45 Clearly, the structure of Mongolia's coal and CHP systems poses constraints to proper market competition. These include the dominant position of CES as major consumer, the dominant position of Baga Nuur as major producer, and the existence of captive markets in some of the aimaks where one small mine supplies its central district heating system. Hence, arm's length regulation will be requii-ed for certain segments. The adoption of market principles, however, is critical and there are two steps to move in this direction: (a) Coal supply contracts between individual mines and consumers should be introduced as the mechanism for establishing agreement on coal deliveries and prices. These contracts should specify agreements concerning responsibilities for transport, quality differentials, and prices. Price agreements should include adjustment clauses for quality variation and production cost escalation. International technical assistance is recommended for the development of coal supply contracts, based on international experience. - 23 - (b) Prices for the output from Sharyn Gol, Shivee Ovoo, and most of the smaller mines should be allowed to float according to market demand and supply. A degree of government price regulation will need to be maintained for Baga Nuur, given its controlling position in the market. The GOM should establish a price ceiling for Baga Nuur coal, based on the average incremental costs of production, and establish procedures for calculation and adjustment of this ceiling. 2.46 As a result of the proposed steps, the industry's structure would shift to a commercial nature. Under this structure, the industry would look as illustrated below. Figure 2.1 Institutional Structure in the Coal Sector under Commercial Contracts Bag Nu ShrnGl ShiveeOo OtrMis CHP Plant 2 CHP Plant 3 CHP Plant 4 Industries NUURS Other Small Consumers Recommended Action Plan 2.47 Summarizing, to increase coal production and meet quality requirements of customers while minimizing costs, the indicated sequence of priorities in the coal sector include the following: * Reduce government's role in determining production, prices and coal allocation targets, and allow consumers to negotiate directly with coal suppliers. Price ceilings should be established by the government for coal produced by the Baga Nuur Mine due to its dominant position in the market. * Define the functions of MEGM and the coal companies to pursue the basic separation of the coal companies from MEGM. Combined with designing and implementing a regulatory and legal framework for energy sector companies, the eventual goal is to create an explicit and transparent system of mine company ownership, corporate management and government regulation. -24 - * Develop coal supply contracts between individual mines and consumers. Implement reforms of CES to give CHP plants outside Ulaanbaatar the flexibility to negotiate their own coal supply contracts. * Improve company management by: (a) developing corporate management capabilities; (b) restructuring and strengthening of financial management and accounting practices; and (c) improving the organization and practices for supervising mine operations. * Rehabilitate the Baga Nuur mine to replace the rail overburden removal system with mobile (truck/shovel) mine equipment and to fully redesign and reconstruct a coal handling plant. * Modest investment in the Sharyn Gol Mine to enable production through the end of the decade. * Further investigate the geological/hydrogeological regime of the Shivee Ovoo Mine to identify the timing and quantities of coal production that can meet quality specifications and investments to allow it to reach its design capacity and improve coal quality. - Further review of the Russian evaluations on the Tavan Tolgoi Coal Area and completion of a preliminary assessment of its infrastructure needs, options and costs. -25 - 3 Combined Heat and Power System Balancing Heat and Electricity Requirements 3.1 The objectives of this chapter are to: a) provide an overview of the Coal- Power-Heat delivery system; b) identify the sequence of priority actions required to increase security of supply and reliability in the near future; and c) identify assistance needs in the next four years. This chapter does not provide a detailed least cost expansion plan of the power and heat sector, an output to be produced under the ADB financed master plan. Once the master plan is produced and properly reviewed, then preliminary tariff estimates provided here will need to be reevaluated. 3.2 This chapter distinguishes institutional, operational and financial issues facing the CHP system. Those issues include: * Institutional - non-commercial nature of the CES' operations and inefficient government intervention in managerial decisions; and - lack of management and financial experience of the CES to restructure the company and operate it as a commercial entity. * Operational - poor quality of coal supplied and lack of experience at the CHP plants in coal inventory management; - high level of forced plant outages, which are mainly caused by the poor quality of coal supplied and poor operational management on plant components and instrumentation systems; and - 26 - - high losses in transmission and distribution in the district heating system and in conversion, own consumption and distribution of electricity. Financial - electricity and heat tariffs substantially below cost of supply; - lack of cash generating capacity at CES to cover operating and maintenance costs, let alone capital investment requirements, primarily due to insufficient tariff revenue; and - high level of subsidies, particularly to industrial consumers of electricity, and to household consumers (totaling about US$50 million per year). * System Design - technical constraints in the power grid to follow load variations, meet peak load demand and regulate the system under random frequency and voltage fluctuations; and - a district heating system designed with constant flow characteristic. 3.3 Consequently--to achieve reliability of supply, self-financing and efficient operation--during the next five years the GOM needs to anchor ongoing rehabilitation and assistance efforts around three main elements: * build institutional capacity at the policy and company levels; * commercialize and modernize the nature of CES' operations, including improved quality of service and tariff adjustments over the next 3 years; and * prepare and implement a legal framework, at the sectoral and company levels, that will eventually attract private sector participation for new investments. 3.4 If done properly--and provided that tariffs are increased in real terms, assets are revalued and management is improved--the CES could have by the year 2,000 a positive rate of return (3.7%), and an improved operating ratio. Overview of the CHP System 3.5 The CES has five coal-fired power-heat cogeneration power plants with total installed capacities of 833 MW electricity and 4,873 MW heat (steam and hot - 27 - water), using coal from Baga Nuur, Sharyn Gol, Shivee Ovoo and other mines. Power and heat production in 1993 was 1,928 GWh and 4,266 Tcal. 3.6 The cogeneration plants use extraction and condensing type turbines. Part of the steam is extracted from the turbines for heating load (steam and hot water) and the remaining part of the steam flow is condensed by cooling water. As seen in the tariff analysis, this technical configuration should be considered in designing an adequate tariff system. District Heating 3.7 Ulaanbaatar is the coldest capital in the world. Indeed, Mongolia is one of the most ir.tensive users of district heating (DH). Similar to Siberia and other central Asian and East European countries, Mongolia's principal DH systems receive heat from CHP plants, and hence are part of integrated urban energy supply systems. 3.8 As highly centralized systems, however, the CHP/DH facilities also have major drawbacks. Particularly with the constant flow technology used in Mongolia, they are not flexible. The design philosophy focuses on supply temperatures of " at least" design levels to all homes as simply as possible, with less concern for minimizing installed heat generation needs, fuel and power and system flexibility. Under this design philosophy, heat levels are adjusted by changing the temperature of water supplied at the CHP plants, which in turn is adjusted depending upon the outdoor temperature. This design has two critical implications: * Systems have been designed to provide adequate heat for units at the "end" of the system, and hence more heat than necessary may be supplied to many consumers "ahead" in the distribution system; and * both housing blocks and individual consumers have no control over their level of heat consumption. Oversupplied consumers close to the heat production source can adjust their level of comfort only by opening their windows. Design Constraints in Electricity Generation 3.9 The power component of the CHP system was designed to operate as an integrated part of the Russian grid. It is composed of coal power plants designed for continuous base-load operation and includes no quick start peaking plants; when a unit is taken off line, it takes 5 to 6 hours to restart and put it on line. Further, auxiliary equipment and control systems arc t t adequate to regulate load variations. These issues have two critical implications: * lack of operational capability to meet peak load demand, particularly in winter time when requirements for heat load dictate the operation and - 28 - dispatch of the power plants, thus limiting the capacity to follow the load; and lack of flexibility to regulate the network's load and frequency variations. 3.10 Consequently, demand variations are now met by limited load changes in the plants and energy imports from the Russian system, even though the import contract explicitly forbids the use of imported energy to regulate the CES system. The operation of the CHP plants under these conditions, compounded by the bad quality of coal supplied, leads to the continuous deterioration of equipment, such as boilers and turbines. For rehabilitation efforts to be sustainable, there will be a future need to build power plants designed to meet peak demand and to regulate the grid. This is unavoidable. Heat and Electricity Demand 3.11 During the 1980s, electricity consumption increased by 7.7% per year, compared to the economy's growth of 6%, reaching 2,800 GWh in 1989. In the following 4 years, however, consumption decreased by 8.5% per year, following declines in economic output, reaching 1,936 GWh in 1993. Peak demand for electricity also decreased by about 180 MW since the early 1 990s. 3.12 The heating sector witnessed similar trends. Heat demand appears to have increased by 5.3% per year in the 1980s, and decreased by 2.9% annually in the last 4 years, reaching about 5,730 Tcal in 1993; 4,300 Tcal for the CES. These demand figures are not accurate since no metering is available. (Figure 3.1). Figure 3.1: GDP/Electricity/Heat Demand Trends (Period 1984-1993) Annual Growth (%) 15 1 0 - ,, - Heat Demand Real GDP O --- - - - - - - - - - - - - - - - -:.- -5 , Electricity Deman an -15 1984 1986 1988 1990 1992 1994 -29 - 3.13 As an indication and assuming a base 1992-2,000 GDP growth scenario of 3.5% per year, real annual increases in tariffs of 15% for electricity and 20% for heat, the historical and projected demand for electricity and heat are shown in Tables 3.1 and 3.2 respectively. Table 3.1: Past and Projected Electricity Sales Electricity Sales (GWh) Average Annual Actual Projected Growth Rate (%) 1990 1992 1994 2000 1990-94 1994-97 1997-00 Industry & Const. 1,803 1,413 1,262 1,325 -8.5 0.1 1.6 Public & Residential 349 308 277 290 -5.6 0.0 1.5 Other 228 236 161 192 -8.3 4.4 1.6 EUOs 352 241 169 180 -16.8 0.6 1.5 Total 2,732 2,198 1,869 1,986 -9.1 0.5 1.5 Source: Mission estimates 3.14 As seen above, by year 2000 electricity generation may reach only 72 percent of its 1990 level. Regarding heat demand, a similar case is presented. Table 3.2: Past and Projected Heat Demand Heat Demand (Tcal) Average Annual Actual Pr_iected Growth Rate (%) 1990 1992 1994 2000 1990-94 1994-97 1997-00 Ulaanbaatar 4,282 3,576 3,432 3,857 -5.4 1.8 2.1 Darhan 738 560 594 621 -5.3 -0.6 2.1 Erdenet 545 455 464 504 -3.9 0.6 2.1 EUOs 1.545 .96 1.450 1,60 -6 1.4 2.1 Total 7,110 6,558 5,940 6,591 -4.4 1.4 2.1 Source: Mission estimates Heat Consumers 3.15 The largest DH system is in Ulaanbaatar, serving around 260,000 people in 45,000 apartments within about 1,200 residential buildings, and 1,800 other buildings, including government offices, schools, universities, hospitals, commercial buildings, and industries. - 30 - 3.16 While the necessary data is not available for the Ulaanbaatar system, Figure 3.2 shows a typical Russian-designed DH system load duration curve, highlighting that: (a) about 30% of the peak load heat level is demanded for only about 500 hours per year; and (b) system losses and hot water consumption directly contribute to the peak load. Figure 3.2: Illustrative District Heating System Load Duration Curve, 1994 100% 90% - 80% - 70% - 60% - 50% - 40% - Space heating: 64% 30% - 20% - 10% - Domestic hot water: 16% 0% - ~~Distribution losses in network: 20% 0% 0 2000 4000 6000 Hours/year Source: Birch & Krogboe A/S, Denmark. Heat and Electricity Supply 3.17 Overall, the power sector has a net installed capacity of about 1,066 MW. The CES' net installed capacity is 833 MW (78% of total) and its firm capacity was only 65% (approximately 541 MW) in 1994. The country's installed capacity for heat pro- duction is about 3,200 Gcal/h, but the current condition of boilers allows a maximum output of only 2,100 Gcal/h (about 66% of the total). - 31 - Table 3.3: List of Cogeneration Power Plants in CES- 1994 Installed Process Year of Capacity Availability Boiler Hot Water Steam initial (MW) (MW) (no. x t/h) (Gcal/h) (th) operation CHPPlantNo.2 24 13 2x35 45 60 1961 2x75 1969 CHP Plant No.3 148 93 7x220 615 200 1968-76 6x75 CHPPlantNo.4 560 340 8x420 1,060 180 1983-91 Darkhan CHP Plant 48 24 9x75 195 80 1965-66;86 Erdenet CHP Plant 36 18 7x75 236 54 1986-89 3.18 The main causes for derating include obsolete design, poor maintenance, lack of spare parts, and poor quality of coal. In power plant # 3, the low pressure boilers operate at around 50 % capacity and the high pressure boilers at around 60 % capacity. Coal quality problems result in unstable combustion and require the addition of fuel oil to maintain combustion. 3.19 To have an idea of future operating conditions, a simulated load dispatching was carried out. The main assumptions employed were: a) current transmission and distribution losses were maintained; b) moderate improvements in efficiency at plants, since the proposed rehabilitation plants are more oriented to improve reliability; and c) minimum reserves of about 10% of peak demand. The results indicate that the best strategy for electricity supply in the 1995-2000 period is: * To continue with current plans to rehabilitate the existing thermal plants to improve their reliability; To study the feasibility of a gas turbine component to be commissioned in 1998-99 to substitute/reduce, if economical, energy imports and how such a component would affect the timing of the construction of large projects for peak load system regulation. If a gas turbine were commissioned, the load balance will look as shown in table 3.4; and To continue with the existing contract for power imports from Russia, considering the option of extending it to higher capacity and energy limits if negotiations result in an average tariff similar or lower than the current one. - 32 - Table 3.4: Projected Power and Heat Capacity Balance 1993 1994 1995 1996 1997 1998 1999 2000 AptuaI Electricity (MW) Firm Capacity 541 541 541 541 541 586 586 623 - CHP Plants 496 496 496 496 496 541 586 623 - Imports 45 45 45 45 45 45 0 0 Peak Demand 450 462 489 492 497 503 510 521 Reserve Margin 91 79 52 49 44 83 76 103 Reserve Margin (%) 20 17 11 10 9 16 15 20 Heat (Gcal/h) Firm Capacity 1,568 1,597 1,597 1,597 1,597 1,597 1,597 1,597 Peak Demand 1,340 1,435 1,388 1,393 1,407 1,421 1,436 1,449 Reserve Margin 228 133 209 204 190 176 161 148 Reserve Margin (%) 17 9 15 15 13 12 11 10 3.20 The current reserve margin for electricity generation, 17% of peak load, could be satisfactory for a power system in normal conditions of operation. However, as shown above, in the case of CES, the margin could deteriorate in the future due to the: (a) unreliable condition of generating equipment, particularly boilers (availability no higher than 60% and forced outage rate over 30% in most plants); (b) bad quality of coal produced by suppliers; (c) uncertainties in projecting current and future demand; and d) uncertainties on the conditions in the heat system. Financial Performance and Cost of Supply 3.21 Over the next 10 years, the power sector and district heating system alone may be faced with investment requirements in the range of US $50 million/year in order to rehabilitate and modemize the system. Hence, a key question is how to meet these needs at a time when large Government budget allocations are not an option? 3.22 Three sources are left: a) debt through extemal borrowing (domestic financial markets are underdeveloped); b) foreign equity and debt through private participation in IPPs, BOT, BOO, for which adequate legislation, tariff systems and repatriation of benefits have to be established; and c) a combination of extemal borrowing and increased self-financing by CES, which requires pricing reforms based on full recovery of supply cost and greater autonomy and accountability by CES. The - 33 - common denominator under these options is the need to adjust tariffs. Other options used in the past are not sustainable any more, including: * Involuntary Credit from Enterprises - Enterprises have already become increasingly unwilling to provide goods and/or service without payment. Bank Credit - Commercial banks are shifting lending towards more credit worthy projects as the banking sector is being restructured. * Donor Financing - This is a last resort that has sustained Mongolia for the last few years. Donor financing is not a substitute in place of tariff reform. Financial Performance 3.23 CES has operating revenues of about US $64 million/yr and zero long- term debt. In 1991-93, CES appeared in official accounts as a relatively stable enterprise, yielding a rate-of-return on net fixed assets of more than 10% (Table 3.5). However, a revaluation of more than 5,000% is needed to align gross assets with new replacement values. By the end of 1994, electricity tariffs were 50-60% of the estimated long-run marginal cost (LRMC). Table 3.6: 1991-1993 CES Financial Highlights (millions of 1994 Tugriks) 1991 i993 1994* Total Revenues 1,245 17,582 25,776 Total Expenses 951 16.870 21.832 Net Income 294 712 3,944 Total Assets 3,108 8,456 302,948 Total Long-Term Debt 1 0 0 Total Equity 3,061 6,541 294,277 Ratios and Indicators Energy Sold (GWh) 7,688 6,810 6,931 Average ElectricityTariff (Tug/kWh) 0.37 7.82 13.55 Rate of Retum (%) 10.9 10.1 2.8 Accounts Receiv. (days) 17.6 44.8 60 * Under Revalued assets. 3.24 By the end of 1994 inflation and devaluation affected CES's financial performance. Electricity import prices increased more than 100 times and fuel expenses nearly thirty fold in current Tugrik terms over the previous two years. As a result, revenues were only just enough to meet CES's cash operating budget, and insufficient to meet any major repair or investment needs. - 34 - 3.25 Financial projections were run to show the impact of rehabilitation investments, revaluation of assets, tariff adjustments, and expected inflation. The results show CES' finances could steadily improve by 1998-2000 with these reforms. Table 3.6: Financial Projections 1995-2000 (1994 billion Tug.) 1995 1996 1997 1998 1999 2000 Operating Revenues 29.7 34.5 40.4 47.3 53.6 56.2 Operating Expenses 43.0 43.2 43.6 44.8 40.7 41.9 Operating Income -13.2 -8.6 -3.2 2.5 12.9 14.3 Total Assets 289.4 290.1 296.1 326.1 363.6 380.5 Long-Term Debt 5.7 15.7 26.3 55.6 84.7 103.3 Shareholders Equity 280.1 270.7 266.2 266.2 266.1 264.6 Ratios and Indicators Avg.Elec.Price 15.6 17.9 20.6 23.7 26.3 26.3 (Tug/kWh)* Avg.Heat Price (Tug/kWh) 0.6 0.7 0.9 1.0 1.3 1.5 Elec/Heat Price (% LRMC) 59/16 68/19 78/23 90/27 100/33 100/40 Rate of Return (%) -4.9 -3.6 -1.8 0.3 3.9 3.7 Debt Service Coverage 6.9 17.3 14.5 12.7 9.6 6.9 Operating Ratio (%) 144.5 124.9 108.0 94.7 76.0 74.5 Source: Mission Estimates. * In real terms; hence, nominal tariffs will need to be adjusted for inflation. 3.26. As shown above, tariff adjustments are critical to restore financial viability to CES, improve service quality and clear inter-company arrears. On the latter, as of July 1995, Baga Nuur coal mine received payments for only one-third of the coal shipped to Power Plant #4 in 1995. This is a structural energy policy issue that cannot be solved through clearing of debts by the central bank. The graph below shows the rate of growth of both payables and receivables for CES early this year. - 35 - Figure 3.3 CES: Receivables and Payables in First Semester of 1995 CES Receivables and Payables 1995 14000.00 a 12000.00 E 10000.00 i 8000.00 o Receivables o 6000.00 FPayables 0 4000.00 20.00 Jan-95 Mar-95 May-95 Source: MEGM, July 1995. Cost of Electricity and Heat Supply 3.27 For purposes of estimating electricity and heat supply costs in CHP plants, where it is possible to produce electricity and heat in variable proportions, the CHP electricity price must not exceed the electricity price from a reference power plant (electricity plant only) while the CHP heat price must--as a minimum-- be the marginal cost of producing heat at the CHP plant and--as a maximum-- the alternative cost of a heat only plant. This criteria has three important implications on our marginal cost estimates: a) a heat unit used in generating heat output represents a benefit equal to the cost due to the electricity not produced; b) the weighted average of heat and electricity tariffs should be equal to the average cost of the cogeneration system; and c) tariffs should be no higher that the cost of production from systems dedicated only to heat and electricity supply respectively. Using these assumptions, preliminary estimates of marginal cost levels at bulk supply and distribution were made. 3.28 One further observation is that even though the average incremental cost (AIC) is generally considered to be a good approach to estimate LRMC, in this case it does not represent the opportunity cost of the system, and tariffs based on the AIC would give wrong signals to consumers. Consequently, the marginal cost for power and heat production were calculated based on the cost of the expansions of both electricity and heat subsectors with single-purpose thermal plants and then combined into a cogeneration system. 3.29 Using the above assumptions LRMCs for the CES cogeneration system have been estimated as Tug 23.2/kWh (US cent 5.8/kWh) for bulk electricity supply and Tug. 4,400/Gcal (US cent 0.95/Kwh) for heat. The LRMC for electricity provided to - 36 - final consumers is estimated at Tug. 26.3/kWh (US cent 6.6/kWh). These estimates compare to current average tariffs as shown below. Table 3.7: Current Average Tariffs, November 1994 Electricity Tug/Kwh (US cent/Kwh) Heat Residential 13.5 (3.4) Tug 30/sq. mt. Industrial 16 (4) Tug 1,463/Gcal (US cent 1.28/Kwh) 3.30 The government has expressed concerns about the inflationary impact of the recommended price adjustments. Past years have shown that in the process of price liberalization Mongolia has been successful in combating inflation. Although peaking at a bit over 400% in 1993 the inflation trend has been decidedly downward with the latest estimates for 1995 hovering around 40%. The 1993 inflation spike resulted mainly from expansionary monetary policies 1992-1993, (the monetary base increased 142% in 1992 and 184 % in 1993) rather than from price liberalization. 3.31 High, continued inflation is usually traced to large and ongoing deficits that are monetized by the central bank. i.e., the central bank prints money to bridge the gap between revenues and expenditures or generating new credit for enterprises. Mongolia experienced this in 1992-1993 when domestic credit to public enterprises increased by 240%. 3.32 In the absence of access to external savings (except through the incurring of arrears) and with difficult and costly internal borrowing, failure to adjust tariffs may indeed contribute, in an indirect way, to inflationary pressures increasing the public sector deficit. Options to Increase Efficiency in the Near-Term Raising Tariffs to Cost-of-Supply Levels 3.33 As table 3.7 illustrates, current average tariffs for electricity and heat are Tug. 16.0/kWh and Tug. 1,463/Gcal respectively; 50-60% and 32% of marginal costs. Under current tariff levels, the CES is being decapitalized. While the tariff analysis will need to be refined when the Master Plan is completed, preliminary estimates show that the bulk of electricity subsidies-- the difference between current tariffs and estimated economic cost of supply-- are focused in the industrial sector and not among the household consumers. In the absence of metering in the district heating system, subsidies by sector are not available. - 37 - Table 3.8: Tariff Subsidies by Consumer Group Average Tariff Reference Cost Industry Subsidy Public & Resid. (Tug./kWh) (Tug./kWh) (US$millions) Subsidy(US$mil) Electricity 16 26.3 31 6.9 Heat/Steam 1.25* 3.68* n.a. n.a. Source: Mission estimates; * Industrial Sector. 3.34 Thus, to improve efficiency in the near-term, the first step is to adjust electricity and heat tariffs to LRMC levels. Moreover, the earlier the adjustments the higher the probability of attracting private capital investment. Further, in the case of electricity, the bulk of adjustments would affect the industrial sector, not households. The latter account for about 14 percent of the demand and based on surveys, electricity expenditures account for only 3.5% of expenditures per household. Adjustments can be implemented in phases and, based on a preliminary evaluation of tariffs it is recommended that tariffs should be increased annually by at least 15% for electricity and 20% for heat, in real terms. By the year 1998, electricity tariffs would reach their LRMC. Heat tariffs, however, woud reach only around 50% of their reference cost. Contract Negotiations with Suppliers 3.35 Imports from Russia. Efforts to maintain and negotiate a better import contract with Russia should be continued. Electricity imports from Russia are needed to meet peak load requirements and compensate for the lack of power plants with the capability to regulate random load variations. 3.36 Contract with Mines. Coal supply to thermal plants (which represents about 70% of coal consumption) should be urgently improved by the establishment of commercial-type contracts between thermal plants and mines, based on "as received" heat rate of the coal and on an automatic mechanism for adjustment of prices. While institutional and operational changes in the mines may take a longer time frame, establishing supply contracts with the mines can and should be undertaken immediately. Optimized Dispatch of Electricity, Heat and Steam 3.37 There are still many unanswered questions regarding the cost interrelationships involved between electricity, heat and steam generation and distribution. While a preliminary approximation to cost allocation for tariff design purposes has been done, answers to the following questions are most urgently needed for operational policy and investment decision making, and to refine the longer-term indicative expansion plan: - 38 - * At what time (season and time of day) does industrial steam supply result in less electricity and/or heat supply than would be the case if the steam was not supplied? What is the (opportunity) cost of any electricity and heat foregone at these times, and how does this cost compare with the cost of independent steam generation at the industrial plant? * At what time (season and time of day) does heat supply, which is usually given priority, force a decline in power generation, causing a corresponding need for increased imports or for shedding of electricity load? * To what extent does domestic hot water supply result in declines in the quality of space heating service? Are options available to reduce the quality of domestic hot water service during periods of peak heating load? 3.38 Regarding heat supply, much of the solution to the current difficulty in providing adequate heat service, however, is not through an increase in firm heat generation capacity. Current and planned investments to rehabilitate CHP boilers to increase reliable capacity are worthwhile and cost-effective, from the combined heat and electricity perspective. However, authorities should not attempt to meet demand for all consumers solely by increasing heat inputs into the whole system through increased CHP heat generation. Rehabilitation in the Electricity Subsector to Improve Reliability and Reduce Forced Outages 3.39 Given the obsolete design of the CHP plants, increased efficiency is a very difficult objective to achieve. Hence, rehabilitation efforts should focus on improving reliability and reducing forced outages. 3.40 Technically, the capacity reserve margin and service reliability could be increased in the short-term by a combination of plant rehabilitation and energy imports. Based on a preliminary evaluation of CHP Plant No. 4, Annex 2 proposes a rehabilitation plan in a 4-year program which costs about US$65-70 million, of which the Government of Japan has committed US $40 million. It is expected that implementation of the first year rehabilitation could produce a 10% increase in production of electricity and heat. 3.41 The main items that need rehabilitation in sequence of priority are9: (a) boilers; (b) coal feed systems and mills; (c) electrostatic precipitators; (d) instrumentation and control systems; (e) turbine-generators; (f) power transformers; and (g) others. 9 Draft Report "Rehabilitation of Power Plant No. 4" K.A.B., January 1995. - 39 - 3.42 The rehabilitation of CHP Plant No. 3 will cost about $40 million and it will be partially funded by ADB. Table 3.9: Estimated Rehabilitation Requirements for CHP Plants No. 3 and No. 4 USS Million CHP Plant No. 4 65-70 CHP Plant No. 3 40 - 50 Other 5- 10 Total 110- 130 Rehabilitation in the Heat Subsector to Reduce Losses 3.43 Conversion of the system from constant to variable flow is of critical importance to enable the system to meet the actual demands of consumers, allow for the introduction of end-use demand management, and provide for proper heat load modulation based on flow control. 3.44 As developed in Western Europe, variable flow systems allow individual consumers to adjust temperature levels. If the consumers require heat the radiators are opened. The variable flow system gives the flexibility to cater to demand variations throughout the system. Additionally, conversion to variable flow could reduce the peak heat load level in Ulaanbaatar by at least 30% due to the following: Conversion will allow the system to capture the benefits of a diversity load factor (load coincidence factor). Not all consumers in the system demand maximum heat levels at the same time. While it might be higher in Mongolia, modern DH systems in western Europe operate with a diversity load factor between 0.6 and 0.7; i.e., peak load is between 60% and 70% of the maximum connected load. * Coupled with tariff reforms and the introduction of improved metering, conversion will provide incentives for consumers to save energy. 3.45 A variable flow controlled system requires design changes at the level of the power plant, distribution system, substations and consumer installations. The basic elements include pumps equipped with speed control, heat exchangers at susbstations, and differential pressure transmitters in the district heating network. Electric power consumption would also be decreased for pumps equipped with speed control as compared with fixed speed pumps. In Ulaanbataar, total annual electricity consumption at the pumping stations is between 80-100 Gwh. While it varies according to operation -40 - regimes, the combination of variable speed pumps and heat exchangers at substations could reduce electricity consumption by about 30-40 %. These are all rough figures that need to be refined in a more detailed feasibility evaluation to assess the shift to a variable flow system. 3.46 Preliminary investment requirements to conduct both repairs and convert to variable flow the district heating system in Ulaanbaatar to variable flow are estimated at about US$77-95 million. (Table 3.10). Total investment required for such conversion is estimated at US$40-50 million. This includes US$20-25 million for substation investments and the installation of variable speed pumps, and about US$25 million for the installation balancing valves in some apartments, thermostatic valves and heat allocators in the commercial buildings. The investments at consumer points could be phased-in gradually. 3.47 Additional investment is needed to replace parts of the network. About 25 km of the primary network in section 5a and 7a needs to be replaced, at a cost of about US$8 million. An additional 14 km of primary pipes has also been identified for early replacement (about US$7 million). Together with the costs of section valve replacements, further rehabilitation work in the secondary system, and improved insulation in the pumping stations, the total additional investment over the five year period are estimated at US$25-30 million. After 2000, investments to gradually replace parts of the system due to normal wear and tear can be expected to average US$10 million per year. These estimates refer to Ulaanbaatar only. Additional funds are also needed for the smaller systems, some of which are reportedly in much worse condition. Table 3.10: Near-Term Investment Needs in the U.B. District Heating System US$ Million Near-term maintenance and repair 12 - 15 Partial network replacement 25 - 30 Conversion to variable flow 40 - 50 Total 77 - 95 After year 2003 1 0/year Institutional Reforms to Commercialize Operations 3.48 Rehabilitation alone is not sustainable. There is a need to improve maintenance and operating practices, develop financial management and accounting systems and a host of other parameters to become a commercial entity. As illustrated below, just in plant #4 every day at least 1 out of 5 boilers is breaking down. - 41 - Table 3.11: Average Operating Hours Without Breakdown CHP Plant No. 4,1994 Boiler# 1991 1992 1993 1 87 114 114 2 96 97 57 3 69 62 104 4 99 109 80 5 114 91 24 6 62 61 54 7 112 62 58 8 104 143 83 Source: 0. Pfluger, K.A.B. "Evaluation of Plant No. 4." January 1995. 3.49 Reforms in the Electric Power Subsector. Institutionally, the MEGM is excessively involved in daily operations of the CES; responsibilities for the expansion of electric service are not clear; and private participation is inhibited due to the monopolistic position of CES and MEGM's role as both regulator and manager of the sector. 3.50 Privatization is not a target by itself, but is one of the options to improve efficiency. Corporatization of CES and regulatory reforms are critical to achieve an efficiency privatization effort. To achieve these objectives, private investors should provide fresh capital and operate in a properly regulated market in those portions of the market where competition is not possible. 3.51 However, to make these possible, it is necessary for the GOM to prepare a time-bound action plan that aims to: * implement a credible tariff reform program in the next three years; * prepare the authorities to take the final decision on sector restructuring through seminars and visits to countries with reformed and privatized sectors; * take immediate measures to improve the efficiency of the MEGM (as a planning institution), CES and coal mines (as commercial enterprises) and the isolated energy centers; * review and complete the draft Energy Law to regulate the CHP system (power and district heating) and to create the new institutions needed, such as the entity in charge of regulating electricity and heat tariffs; and -42 - prepare a program for privatization of activities in the energy sector, particularly to facilitate the entry of new private investors in the power sector. 3.52 Reforms in the District Heating Subsector. Specifically for district heating, the GOM should establish district heat companies which are fully separate and independent from the CES, building, in Ulaanbaatar's case, on the existing Heat Dispatch Center. The companies should be given autonomy for operation of the system within parameters specified by the GOM, and should be held accountable for both their service and financial performance against specified criteria. 3.53 Key changes which can be expected to increase efficiency and technical and financial performance include: (a) establishment of a formal contractual arrangement between the DH companies and the CES (or CES' CHP plant subunits), including the amounts and parameters of heat supply and a transfer heat price which fully covers all of the capital and operating costs of CES' supply; (b) provision of any continuing subsidy payments for heat directly to either the consumers or the DH companies, and no longer to CES, through transparent and clear government transfers; (c) establishment of commercial operating principles within the DH companies, with proper accounting and financial reporting functions; and (d) implementing manpower planning and designing explicit incentive schemes and training programs. As experience progresses, the GOM should consider options for restructuring the ownership of the DH companies, perhaps to include shareholding by the relevant housing cooperatives, municipal governments or a combination of these. Security of Supply and Reliability of CHP System 3.54 A recurring issue related to the expansion of the power sector is the degree of reliable self-sufficiency that the country must have to be able to respond to disruptions in local production or energy imports. With insufficient peaking capacity in the domestic system, Mongolia's system remains highly dependent upon the interconnection with Russia. To improve the reliability of supply, the first priority remains to improve reliability in existing facilities, regardless of future expansion plans (see graph below). - 43 - Figure 3.3 CES Power Expansion Plan - Firm Capacity (High Demand Scenario) MW 700 -; 600 - Peak Demand > . . \ _,,,,<~~~~~~~~ Peak ~~Futtre 500 -oIts r 300 - CHP~~F #4 100 CHP #3 O mISmal PS l 1990 1991 1992 1993 1994 1995 1996 1997 1998 1999 2000 3.55 For peak electricity production and system regulation, DGT (110 MW) entails expensive operating costs, but it still may prove attractive, especially given the short construction periods and the high flexibility of such systems. Regarding Egiin, based on the preliminary information available, this plant may be a long-term solution for peak energy production with an acceptable cost and load regulation, and hence it deserves to be evaluated in more detail. However, this evaluation must take account of the effects of changing to variable flow in the district heating system as well as improvements in the CHP plants derived from the rehabilitation, particularly new instrumentation. This will allow coal-fired plants to operate with fewer load variations, saving O&M resources and increasing their plant life.'" 3.56 While the Egiin Hydro Project may be technically sound, the main drawbacks of this option are the financial constraints of the GOM and CES to initiate a project of such magnitude ( about US$275 million, close to 40% of GDP by year 2000) and the lack of institutional capacity. Private sector participation may be the answer to this issue if a satisfactory institutional and regulatory framework is implemented soon. '° Load regulation provided by electricity imports is poor, since the transmission distance is significant and the exporter is not interested in investing in additional equipment to improve system regulation. -44 - Recommended Action Plan 3.57 To secure the efficiency and reliability of the CHP system and to lay the groundwork for the sustainability of the sector, the near- and longer-term priorities would be to: Near-term priorities: - completion of Master Plan; - adjustment of electricity and heat tariffs over next three-four years; - evaluate options for optimizing the dispatch of electricity, heat and steam, including a detailed assessment of the economics of converting the DH system to variable flow; - rehabilitate CHP Power Plants No. 3 and No. 4 to improve reliability and reduce forced outages; - rehabilitate the DH network distribution system to reduce losses, through repairs and maintenance; - reform and restructure the CES into commercial enterprises (electricity and district heating), with sufficient contractual arrangements between CES and DH companies; - redefine MEGM's role as planner and policy-maker of the sector, provide sufficient managerial and financial autonomy to the CES, and design appropriate legislation and regulation to attract participation of the private sector in electricity and DH investments; - develop the CES and DH companies through manpower development and training to allow them to operate as commercial entities; and - negotiate an electricity import contract, including seasonal price distinctions, and analyze the power regulation capacity and charac- teristics of the Siberian power system. - 45 - 4 Isolated Energy Systems The Need for Change 4.1 In 1993, total financial transfers to the isolated energy systems from the central government, coal mines, NIC and transport companies reached Tug. 6 billion. Despite this, the physical infrastructure of the Energy Utility Organizations (EUOs) and the levels of service they provided have been declining to the point where donor assistance was needed to avert breakdown of the systems. Fundamental changes are needed to ensure sustainability of the EUOs in the future. Based on findings, the strategy for reform should include the following elements: over the near-term: - efficiency improvements in the use of diesel and coal for electricity and heat; - institutional strengthening through manpower development and performance monitoring; and - financial and managerial autonomy to allow EUOs to operate as commercial enterprises. * over the medium-term, to conduct a detailed evaluation on the economic opportunities for using renewable energy sources. Isolated Energy Supply and Demand Electricity and Heat Supply 4.2 The soums and aimag centers which are not connected to CES receive heating and electricity services from isolated energy supply stations. Each isolated energy supply system consists of diesel engine generators for electricity supply and heat- - 46 - only-boilers (HOBs) for district heating services. Currently, there are isolated stations at 218 of Mongolia's 316 soums, and 11 of the 18 aimag centers. Isolated stations within each aimag are operated by an EUO (Map 2). 4.3 Isolated power systems range from two 60 kW diesel engine generators in the smallest soums to a 7.2 MW facility in the aimag centers. Performance monitoring of diesel engine generators is poor. Information reported by the MEGM specifies specific fuel consumption (SFC) rates ranging from 475 g/kWh-delivered (corresponding to a conversion efficiency of 18%; indicative of poor performance) to 250 g/kWh-delivered (34%; characteristic of a well operating system). 4.4 Both hot water and space heating are supplied by manually-stoked, coal- fired shell and tube HOBs. Boiler capacities range from 0.4 to 10 GCal/hr at approximately four bars steam pressure. District heating systems, that may include multiple boilers for a single soum or aimag center, provide constant flow, variable temperature hot water. Performance monitoring at the HOBs is poor since there are no instrumentation and controls to monitor the amount of heat supplied. The MEGM assumes a nominal 50% efficiency (coal to end-use) to compute the energy delivered to the consumers. However, inspection of boiler operations, piping insulation, and water leakage at Bayan Hongar and Uliastai aimag centers indicate that overall losses are greater than 50%. Consumption Trends 4.5 Due to increased tariffs, a down-tum in economic activity, and reduced government budgetary allocations, demand for electricity and heating services has been sharply reduced. Electricity production in 1995 is estimated to be approximately 50% of output in 1990. Only those supply systems that require electricity for HOBs (i.e., for motors driving pumps, blowers, etc.) during the winter months provide 24 hour electricity service. During the summer months in smaller soums, poor part load efficiencies of the diesel engines have increased production costs beyond what subsidies and tariffs can cover. As a result, summer service has been eliminated. Pricing 4.6 The present practice for setting electricity and heat service tariffs is for the EUO to propose a tariff schedule based on production costs to the Price Setting Committee (PSC) of the aimag administration. The prices set by the PSC are below production costs and the subsidy provided by the MEGM does not cover the deficit. 4.7 EUOs serving aimag centers and larger soums meter electricity to customers who are charged on a kWh basis. These tariffs have increased significantly over the past several years from uniform rates of Tug. 0.25/kWh in 1990 and Tug. - 47 - 1 5/kWh in 1994, to negotiated rates of Tug. 24/kWh in Suhbaatar, Tug. 25/kWh in Govi- Altai, and Tug. 29/kWh in Hentii for 1995. Customers in smaller soums are charged a fixed monthly fee based on their number of service points (i.e. light fixtures and outlets). 4.8 Heating charges are based on area of heated space for residential consumers and volume of heated space for industrial and commercial customers. Heating charges prior to October 1994 were Tug. I 9/m2/month in the residential sector and Tug. 100/m3/month in the industrial sector. Domestic hot water charges are based on the number of persons per household. A comparison with CES' electricity and heat tariffs is illustrated in Table 4.1 below. Table 4.1: Electricity and Heat Tariffs, 1995 (Tug.s) CES Isolated Systems Electricity: Industry 16/kWh5O/kWh Household 1 6/kWh22/kWh Heat: Industry 1,312/Gcal 100/cu meter Household 30/sq meter 19/sq meter Public 34/cu meter Subsidies and Taxes 4.09 Due to taxes paid by EUOs to GOM for fuel, lube oil, and other products, the subsidies received by EUOs do not present a transparent portrayal of transfer payments. Profit margins for oil importing companies and interest payments to banks paid by EUOs further obscure their financial status. For example, in 1995, taxes, oil company profits, and interest payments to banks are expected to total over 60% of direct subsidies issued by the MEGM (Table 4.2). Table 4.2: Estimated Transfers to EUOs, 1995 Direct Subsidy to EUOs 5,445 Taxes Customs, Special & Commercial Taxes - Diesel Fuel -1,417 Taxes on consumable, parts, etc. -149 Commercial Tax on Coal -122 Customs, Special & Commercial Taxes on Gasoline for Coal Transport -327 Sales Tax on Revenue Earned -914 Total Direct and Indirect Taxes Paid by EUOs 2,929 Oil Company Profits -116 Interest Payments to Banks -282 Net Payment to EUOs 2,119 Mission estimate: Computed from financial cost differentials in Annex 1. Based on 1994 oil products tax structure, 10% commercial tax, and consumption of 300 liters of gasoline per transport of 10 tonne of coal (average of 400 km round trip). Diesel consumption for electricity production is 300 gm/kWh. - 48 - Triangular Debt 4.10 A major problem affecting the financial health of EUOs is the rolling debt between the government (both as an energy services consumer and as a supplier of financing), EUOs, and suppliers. The government owes EUOs both overdue subsidies and payments for electricity and heat services. The government is also in arrears to government employees, consequently delaying their payments to EUOs for energy services. To continue operations, the EUOs defer paying suppliers, postpone or eliminate maintenance, or borrow money from banks. Courses of Action to Achieve Sustainability 4.11 To make the EUOs sustainable, near-term actions include autonomy, institutional strengthening, and energy efficiency opportunities. Medium-term actions include renewable energy alternatives. Financial and Managerial Autonomy 4.12 The distressed state of the EUOs is primarily caused by interference from the GOM which prevent them from operating as a commercial enterprise. Initially, the GOM should instill a hands-off policy in the following areas: 4.13 Tariff Rationalization. EUOs should be detached from the present subsidy system and be allowed to raise the tariff to cover their full cost of production including system overhaul costs. To protect vulnerable groups, subsidies should be provided to them directly. Initial estimates show that the effective rate for heating needs to be increased by about 50%. As illustrated in Table 4.3, the approximate rate of increase in electricity tariffs should be about 16-17% per year (in constant Tug.s). - 49 - Table 4.3: Indicative Example of Electricity Tariff Adjustment Residential Tariff Non-residential Tariff Subsidy Year (Tug.s/kWh) (Tug.s/kWh) (billions of Tug.s) 1995 22 50 2.9 1996 26 58 1.9 1997 31 68 0.9 1998 35 78 0 Assumptions: Residential consumption is 70 percent of total consumption. Consumption is 180 million kWh per year (1995 consumption level). Production cost is increased from 1995 level estimated by MEGM by 1 billion tugricks/year to cover additional overhaul costs but is offset by fuel costs decrease by 0.8 billion tug. due to efficiency increase. The subsidy proposed for 1995 is 3.3 billion tug. Prices in constant 1995 tug. 4.14 Curtailment of Service. Since tariffs will be adjusted in increments, there will be a lag in reaching full production costs. During this lag, curtailment of service may be required. This is a particularly effective option because fuel accounts for more than 75% of operating costs. Service could be restricted to non-essential consumers during non-critical periods of the day. In fact, some aimag centers and many soums are already curtailing service to residential consumers and, at times, to non-domestic consumers. 4.15 Ensuring Prompt Payment. EUOs should be given the authority to enforce prompt payment of its customers. Late payments result in overdue payments to EUO suppliers, borrowings at high interest rates, and/or postponement of maintenance and essential repairs. Institutional Strengthening 4.16 However, for autonomy to take place and become effective, EUOs need to have the institutional capacity to operate as independent commercial entities, accountable for their performance. The institutional capability of EUOs can be strengthened by the following: 4.17 Manpower Development and Training. Each EUO should have a long term manpower development and training plan, and allocate adequate resources for implementation. Training programs must be coupled with appropriate incentive schemes to ensure their effectiveness. The MEGM should assist EUOs by establishing appropriate training facilities. - 50 - 4.18 Performance Monitoring. A program of improved performance monitoring should be implemented, which include human resource, commercial aspects, financial indicators and technical targets. Energy Efficiency Improvements 4.19 Cost effective energy savings can be realized by improving infrastructure and O&M practices. Considering the number of potential opportunities, the first step is to undertake an energy audit and feasibility study to determine the most cost effective options and to develop an investment plan. Furthermore, the efficiency improvements in Table 4.4 should be considered. Table 4.4: Efficiency Improvements and Expected Savings Improvements Savings Power Lowering SFC so 250 g/kWh 23% reduction in annual fuel expenditures Heat Proper coal handling, boiler 30% reduction in coal consumption or improvements & DSM measures savings of Tug. 1.2 billion/yr Savings over Installation of waste heat recovery Tug. 45 million/yr systems 4.20 Electric Power Sector. Achieving more efficient SFC is possible by operating diesels at optimal loading, reducing T&D and non-technical losses, and through proper maintenance and regular overhaul. Installation of choking valves will allow diesels to operate at low loads (5-10% of rated capacity) without significant losses in efficiency or engine life. If an average SFC of 250 g/kWh is achieved, annual diesel fuel expenditures could be reduced by 23%. 4.22 Heat Sector. Proper storage, sizing, and handling of coal, efficient firing techniques, and improved boiler O&M offer boiler efficiency improvements. These measures, coupled with improved piping and building insulation, reduced water leakage, and consumer education, may provide a 30% reduction in coal consumption; an annual savings of Tug. 1.2 billion/yr. 4.23 Savings may also be realized from the installation of commercially available waste heat recovery systems at diesel generators. A preliminary analysis of the potential energy savings from such an installation at Uliastai aimag center in Zavhan indicates energy savings in excess of Tug. 45 million/yr, compared to Zavhan's estimated 1995 heating subsidy of Tug. 67 million. The results of the preliminary analysis warrant a more detailed energy audit and feasibility study of diesel engine waste heat recuperation. - 51 - Renewable Energy Options 4.24 Over the medium term, the following renewable energy options should be examined: 4.25 Hydropower. The MEGM has identified a large number of hydropower development sites, primarily in the north-central and north-western parts of the country. A 2 MW plant is under construction in Zavhan aimag and feasibility studies of two other sites are in progress. A prefeasibilty study is recommended to identify the most cost- effective sites and to define a development strategy. 4.26 Wind and Solar Photovoltaics for Nomadic Herdsman. Since there is limited production capacity and even less supply infrastructure, key initiatives for dissemination of wind and PV systems include strengthening the capacities of private sector supply, market, and service. 4.27 Wind. Sites for development investigations have been identified, particularly in the southern third of the country, and should be visited during a reconnaissance mission. Subsequent activities include resource assessments (for at least one year), detailed studies, designs, tendering, and construction. 4.28 Geothermal. Several potential sites have been identified. However, further investigation including surface water analyses, geophysical and geochemical tests, and pre-feasibility studies are warranted. Recommended Action Plan 4.29 The following actions will be needed to develop an investment program and technical assistance plan to improve the technical and financial performance of the isolated energy systems: Proposed High Priority Actions (next 1-5 years) * Electricity and heat pricing adjustments, and price impact mitigation study; * EUO electricity and heat supply system efficiency improvement study, including energy audits, feasibility assessments and development of an investment plan, particularly in schools, hospitals and administrative buildings; * Institutional assessment and design of a manpower development plan, including staffing requirements and incentive schemes; and - 52 - Training needs assessment and development of a training plan for EUO financial management, administration, and O&M of the energy supply system. Proposed Medium Priority Actions * Reconnaissance mission to assess geothermal energy potential and to design a development plan; * Prefeasibility study of hydropower power development; * Reconnaissance mission to assess wind resource potential and to develop a resource assessment plan; and * Development of a program to establish a supply, sales and service network for small wind generators and solar PV systems for use by nomadic herdsman. - 53 - 5 Downstream Petroleum Operations Regional Trends and Reliability of Supply 5.1 Mongolia has no oil or natural gas production. Historically, and to date, the country's entire petroleum requirements depend on imports of refined products from the former Soviet Union (FSU). The breakdown of CMEA trade arrangements with FSU has made petroleum product imports extremely unreliable. On the distribution side. inefficiencies exist from the physical distribution of products to the pricing system which has created cross-subsidies amounting to Tug. 1.8 billion. Thus for the future, the objectives in the downstream petroleum sector are to improve the reliability/security of supply and increase efficiency in distribution. To achieve these targets, the GOM's implicit strategy for the petroleum sector has the following main elements: * diversification of supply sources, both encouraging domestic exploration and diversifying supply arrangements of imported products; * liberalizing petroleum prices; and * promoting competitive domestic and foreign private sector involvenient. 5.2 As a landlocked country between Russia and China without crude oil production and refining capacity, Mongolia's diversification options are limited to supply of petroleum products from these two countries and transit of imports from third countries through these two countries. Transit through Tianjin in Chira would be the most relevant transit option, because of closer access to the sea. 5.3 The petroleum sector is changing rapidly in both neighboring countries. In Russia, the petroleum sector is under restructuring and privatization. Major investments are required to stop crude oil production from falling and refineries are technically obsolete and need to be modernized. Major excess refining capacity is available in some part of Russia and the upstream and downstream oil sector is in a process of vertical integration. Allocation of crude oil to refineries was planned to expire - 54 - as of January 1, 1995. They are, however still in place. At present some companies have export permits for petroleum products. For the remaining refineries there is an export ban. Major changes are expected in the sector over the rest of the decade in moving towards a market economy and international prices. Hence, this uncertain environment could affect Mongolia when trying to secure long term contracts. 5.4 China also is restructuring its petroleum sector but at a slower pace and without major privatization of existing assets. Due to a strong economic growth demand for petroleum products have been soaring and China has recently become a net importer of both crude oil and most petroleum products. However, regional differences within China are large and, like Russia, there is excess refining capacity in parts of the country. Railroad capacity for transit of petroleum products and limited port facilities could cause future bottlenecks. 5.5 Within this regional environment, the reliability of supply drives the Government's efforts in downstream operations. Therefore, in the final decision it is important to look at both cost as well as security of supply as the key objective functions. The rest of this chapter deals with these factors. Petroleum Products Supply and Demand Supply Source 5.6 Based on spot purchases, more than 90% of petroleum imports come from the Angarsk refinery delivered by rail to the main depots along the trans-Mongolian railway, and the balance is imported from the Achinsk refinery delivered through depots to North West Mongolia by truck. An estimated 95% of the petroleum products are imported and marketed by a joint-stock company (20% private-owned, 80% government), Neft Import Concern (NIC). The balance is private imports of gasoline, diesel oil and fuel oil from Russia. Private importers are wholesalers and filling stations. NIC owns and operates its depots and has a total of 342 filling stations throughout the country. Consumption Trends 5.7 Consumption of petroleum products peaked in 1988 at 859,300 tons oil equivalent (toe). Due to the economic downturn, higher consumer prices and supply constrains caused by the breakdown of traditional barter arrangements with the FSU, consumption of petroleum products was drastically reduced to 422,200 toe in 1993, less than half the 1988 level. The total for 1994 is expected to reach only 383,700 toe only. 5.8 Gasoline and diesel oil account for around 80% of petroleum consumption. While gasoline is used mainly for transport, non-transport use of diesel is - 55 - mostly for motorized equipment in the industry and agriculture sectors. Fuel oil is used in power generation, heating plants and industry. 5.9 Table 5.1 shows the demand forecast to the year 2000. From 1994, petroleum product consumption is expected to increase by 4.2% per annum, resulting in a consumption level of approximately 492,100 toe by year 2000, which was the level of petroleum consumption in 1992. Therefore, infrastructure such as depots, trucks, etc., are in place for a much larger consumption. It is expected that consumption of petroleum products will not reach the high levels of the past because fuels were merely allocated and prices had no relation to international market levels. Table 5.1: Petroleum Products Demand, 1993-2000 ('000 toe) 1993 1994 1995 1996 1997 1998 1999 2000 est. Gasoline 161.5 156.6 164.3 173.4 184.1 195.8 208.7 223.0 Diesel Oil 165.2 147.7 150.6 153.9 160.2 166.0 172.9 180.2 Aviation Gasoline 0.4 0.1 0.1 0.1 0.1 0.1 0.1 0.1 Jet Fuel 19.1 17.5 17.6 17.6 17.8 18.0 18.2 18.4 Fuel Oil 69.0 54.7 56.6 58.3 62.0 60.6 61.7 63.1 Lubricants 7.1 7.1 7.1 7.2 7.2 7.3 7.4 7.5 Total 422.3 383.7 396.3 410.5 431.4 447.8 469.0 492.3 5.10 The highest growth will be in gasoline consumption, at 6% per annum. Projections of GDP show a growth rate of 2.3 % in 1994, and 3-4% until 2000. While vehicle fleet is expected to rise faster than the economy's growth rate, savings induced by increasing prices to international levels and imports of higher efficiency cars would tend to taper growth in gasoline demand. Diesel oil consumption, projected at 3.4% per year, could rise faster spurred by growth outside the transport sector such as in power generation. However, no significant displacement of gasoline by diesel is foreseen in the medium-term. Fuel oil consumption is expected to grow at 2.5% per year, spurred by growth in industry and power generation. Growth in demand for aviation gas, jet fuel and lubricants is expected to be minimal at less than 1% per year. Pricing 5.11 Current prices reflect their import parity cost, both in terms of their levels and structure. NIC sets consumer prices for all its products except for gasoline and diesel oil which are subject to approval by the GOM (MOF and the Prime Minister). Private - 56 - filling stations in Ulaanbaatar can charge higher prices . In calculating retail prices for a budget year, NIC estimates import prices and taxes and adds a margin for distribution costs, financial charges and capital expenditure. If significant differences between estimates and actual costs occur, prices are changed to secure the margin. Smaller adjustments are included in the margin for the following year. This cost-plus pricing policy, however, does not provide incentives to increase efficiency. 5.12 Import prices from Russia are based on the Singapore market price plus a transport cost US$14 per ton for all products to the border. Tables 5.2 and 5.3 show the level and structure of petroleum prices as of November 1994. Consumer prices were significantly increased in the last two years. For exarnple. the price of gasoline was increased from Tug. 19,000/ton in June 1992 to Tug. 158,800/ton in November 1994 (US 1.45/gallon). Taxes account for 15-32% of domestic prices; the highest is for gasoline. Transport costs comprise 6-44% of petroleum prices; the highest is for aviation fuels, lowest is for lubricants. Table 5.2: Petroleum Product Price Levels, November 1994 (US$/ton) (Tug.s/ton) Import Import Customs Special Commer- Road Distribut- Sales price price tax tax cial tax funds ion cost Profit Price Gasoline A-76 172.9 70,872 10,631 12,225 9,373 22,230 35,140 10,529 171,000 Gasoline A-93 176.3 72,300 10,845 12,472 9,562 28,080 44,388 38,353 215,999 Diesel Oil 183.7 75,315 11,297 17,322 10,393 2,340 36,990 26,343 180,001 Aviation Gas 200.0 82,000 12,300 9,430 29,962 12,108 145,800 Jet Fuel 202.0 82,840 12,426 9,527 27,105 2 131,900 Fuel Oil 86.8 35,600 5,340 4,094 11,652 14 56,700 Lubricants * 692.0 283,720 42,558 32,628 17,479 500 376,885 *As of July 1994. Source: NIC. Given the uniform price policy for uetroleum products plus the privatization of gas stations, in the future this may give raise to rents [Ling captured by the private stations. - 57 - Table 5.3: Petroleum Product Price Structure, November 1994 Import Petroleum Distribut- price taxes ion cost Profit Gasoline A-76 41% 32% 21% 6% Gasoline A-93 33% 28% 21% 18% Diesel Oil 42% 23% 21% 15% Aviation Gas 56% 15% 21% 8% Jet Fuel 63% 17% 21% 0% Fuel Oil 63% 17% 21% 0% Lubricants* 75% 20% 5% 0% * As of July 1994. Source: NIC. 5.13 All taxes are calculated at the border. The taxes shown in Table 5.2 are calculated as follows: customs tax (15% of import price), special tax (15% for gasoline and 20% for diesel of import prices, including customs tax) commercial tax (10 % of import price, including customs and special taxes), and tax to road funds (13% for gasoline and 1.3% for diesel of the domestic price). The special tax was introduced to raise the GOM's revenue and to reduce the profit of NIC. Around a quarter of the GOM's tax revenue comes from petroleum taxation. 5.14 Uniform Prices. The total average distribution costs for all products to the 26 aimak depots and from the depots to filling stations vary from Tug. 13,375/ton in Ulaanbaatar where they are lowcst, to Tug. 68,253/ton in Maint and Tug. 61,973/ton in Hovd where they are highest. However, throughout the country, a uniform pricing policy applies for NIC's sale of gasoiine, diesel oil and lubricants. Gasoline is paid with coupons purchased by customers in banks and depots and as long as the coupon system is applied, prices will remain uniform. Uniform pricing has led to a cross-subsidy of about Tug. 1.8 billion (US$4.4 million).'2 5.15 Liberalization of prices is being implemented in phases: The first phase made petroleum prices a function of international price variations; GOM approval is pending for gasoline and diesel oil. The second phase, which is currently taking place lifts the uniform price polic:. and eliminates the coupon payment system for gasoline 12 Based on the distribution cost figures above, the cross-subsidization to remote regions can be estimated based on the difference between the actual distribution cost (up to $166/ton) and the average distribution cost of $60/ton which the uniform price policy is based on. Of the 325,000t petroleum products planned to be distributed in 1994, 1 12,865 tons (35%) is sold in Ulaanbaatar and 99,024 tons (30%) is sold in aimaks where distribution costs are above average. - 58 - purchases to allow competition in the import, transport and distribution/marketing of petroleum products. The last phase will be to liberalize gasoline prices completely. 5.16 Barriers to Entry. The downstream petroleum industry chain has three main elements: imports, local transport and retail distribution. As an input in evaluating barriers to entry, Mongolia's petroleum market is relatively small, around 8,000 bbl/day. On imports, three barriers come to mind on any market: a) legal restrictions to import; b) lack of import terminals--or legal restrictions to allow private sector participation; and c) a discriminatory fiscal treatment to different importers or by crude and products. From the reviewed documents, anybody can import products into Mongolia under equal fiscal treatment. Regarding import terminals it is clear that, due to economies of scale and cost competitiveness, importers would have to pool together their imports, otherwise smaller parcels will command higher import costs. 5.17 Right now, there are no import terminals on the Chinese border. If they are built, there would be a need to ensure access under a fair terminal fee by other importers. In conclusion, the only current barrier is the lack of import terminals to diversify sources of supply. The project evaluation of the import terminal also should include, as part of its economic evaluation, the cost of rationing in case of disruptions from their current source. 5.18 Regarding local transportation and filling stations, there are no special barriers for opening filling stations with the exception of Government approval for safety reasons. The high transport costs involved in transporting products to the remote areas where filling stations are being privatized may prove to be a barrier to entry to the business. 5.19 As the schematic below shows, access to the urban storage facilities also should be ensured as is the case today with NIC. If that is provided, one can conclude that there are no barriers to entry in the industry except for the lack of import terminals on the Chinese border (Figure 5. 1). - 59 - Figure 5.1: Downstream Supply Structure Supplies from Russia Import Transport Rail & Trucking (state-owned) Urban Storage NIC Retail stEH Privatization: Institutional Aspects 5.20 Petroleum Import Concern (PIC) was turned into a joint stock company under the new name NIC on July 22 1994. 20% of the shares was sold against vouchers based on the Corporate law of July 1991. The remaining 80% of its shares is state owned. 5.21 In the first stage of the process, four new subsidiaries were created to be responsible for trade, distribution, construction, and lubricants (Figure 5.2). The parent company, NIC, imports petroleum products and equipment. The trading company is responsible for the operation of depots and filling stations, the distribution company for transports, and the construction company for the construction of filling stations and depots. Joint ventures are being negotiated with a Russian company for equipment and with Shell for the marketing of lubricants. - 60 - Figure 5.2: NIC and its Subsidiaries, 1994 a Trade || Distribution I |IConstruction Lubricants 5.22 Trucks deliver products from the main import and secondary depots to filling stations. Around 40% of all trucks used for petroleum distribution are owned by NIC. The remaining 60% is mainly distributed bv state companies privatized up to 49% of their shares and some private transporters. 5.23 In the second stage, of NIC's 342 filling stations, 70 stations located outside Ulaanbaatar will be sold, not through the voucher system but on a "cash sale" basis, to private investors beginning in 1995. The bidding is also open to foreign companies and they do not have to fulfill special requirements. The filling stations will operate under a franchise agreement with NIC based on a commission. 5.24 In Ulaanbaatar, 8 of the 16 filling stations are private-owned. The private filling stations sell petroleum products at around 20% above NIC's prices which customers are willing to pay since private stations accept cash payments and offer higher service levels than NIC's stations. 5.25 In stage 3, another 29% of NIC's shares will be sold in the stock exchange. This stage is being discussed with the Privatization Committee and is awaiting the Security Law to be ratified by the Parliament. The law will introduce a secondary market for share-trading. When this stage is completed, the private share of NIC will be 49% and 51 % will remain with the GOM. Courses of Action to Improve Supply Reliability and Distribution Efficiency 5.26 To improve the reliability and efficiency of petroleum products supply, actions are needed to diversify import sources, liberalize prices, and attract private sector participation under competitive conditions where applicable. Given the uncertain nature of the regional petroleum market, it would be misleading to estimate a least cost supply option at this stage. Still, trends can be provided, as done below. Key variables include the future status of the Angarsk refinery. If this refinery were to be closed, the next source of supply would be Aschinsk refinery, which is about 1,200 Kms from Ulanbattar (versus supplies from Tianjin in China). -61 - Diversification of Import Supply Sources 5.27 Although the supply of petroleum products (except gasoline) from the Angarsk refinery is cost competitive with other potential options, as stated before the future of the refinery is uncertain and Mongolia may be forced to import from other Russian refineries resulting in higher import costs. 5.28 Angarsk Refinery. As a first step, long-term contracts for product supply from Angarsk refinery should be secured. 5.29 Mongolia's import requirements account for less than 2% of Angarsk's refining capacity and the prices which Angarsk obtains for exports to Mongolia are attractive compared to supplying products in its domestic market. Import prices for petroleum imports from Russia are linked to Singapore quotations plus a premium for transport from the refinery to the border and another premium for quality (such as lower sulfur than Singapore quotations). 5.30 However, this does not present a long-term solution. Russia's petroleum sector is being restructured and privatized, and plans are to increase domestic petroleum prices to international levels. Further, Angarsk receives its oil by pipelines from western Siberia, some 2,300 km from the refinery. The market for its products is scattered over east Siberia where it would be more viable to supply customers from other sources. In 1990, only 60% of the products refined in east Siberia were consumed in the region. The balance was sold in other regions. Due to the high transport costs for crude oil and refined products, the financial position of the Angarsk refinery is weakening. 5.31 Imports from China. However, to diversify risk in the long-run, supply agreements with refineries in northeastern China (perhaps including a swap-arrangement) could be pursued if the capacity for refining lighter products is available. Assuming a transshipment terminal is put in place, this option could enhance the security of petroleum supplies. Alternative supplies from China also could improve the negotiation position of Mongolian imports from Russia while potentially reducing import prices and improving product quality. 5.32 In 1993, the total refinery capacity of China was 164 MMTY and the utilization rate was 75% due to excess capacity, particularly in heavy products. Consumption has grown fastest in the southeastern provinces while most of the refinery capacity is located in the oil producing north eastern provinces closer to Mongolia Expansion plans for refinery capacity are plentiful. Many projects are entering into joint- ventures with foreign partners and about 70-75% of the new refining capacity is to be added in the coastal and south eastern areas. The government encourages any refinery with excess capacity to process foreign crude, including third party processing. - 62 - 5.33 Imports from Singapore. The price of imports from Singapore delivered to Tianjin, China would be around the same level as the border-price for Russian imports to Mongolia for diesel oil; higher for gasoline and lower for fuel oil. The estimated transport costs from Tianjin to the Mongolian border would require an additional $5-10 per ton. Alternatively, for products that are in excess supply in the northeast but in under supply in the southern part of China, swap-arrangements may be secured to import products from Singapore to the southern China and export products from the northeast region to Mongolia. Refining may be arranged under a third party processing agreement. Price Liberalization 5.34 Price liberalization is on the right track: the domestic price level is in line with international prices, the price structure is right and NIC's uniform price system is planned to be replaced by a more flexible pricing policy. There is limited, but growing, price competition in Ulaanbaatar. Some elements, however, need careful monitoring: (a) NIC's has a role as a price leader and the linkage to international prices is not automatic but is subject to GOM approval for the most important petroleum products based on NIC's costs; and (b) the uniform price policy should be eliminated as planned, even prior to privatization of the filling stations. Otherwise, investors will capture the rent by focusing only on those aimaks where distribution costs are below the GOM's uniform price, and the cross-subsidy that exists at present will become a "direct" subsidy by NIC to the more distant aimaks. Privatization and Competition 5.35 The privatization program is moving in the right direction and there is a limited but growing competition in Ulaanbaatar. The premium paid for petroleum products at private filling stations in Ulaanbaatar was caused by limited competition. This is, however, changing with the construction of new filling stations with higher service levels. The 70 filling stations to be privatized are in remote areas. An issue is whether the GOM will allow flexible pricing where one filling station has a monopoly in a geographic region, which is the case in almost all the 70 filling stations. There are also some drawbacks concerning the planned structure for the petroleum sector which may discourage some private investors: NIC will continue to have a dominant position in the petroleum sector; the GOM will remain as the majority shareholder of NIC and will act as regulator of petroleum prices. In essence, the linkage of consumer prices to international prices should be clear and transparent and if the GOM retains majority ownership of NIC as planned, its regulatory and policy function should be split. 5.36 The estimated 5% of petroleum products imported from Russia by private companies other than NIC is expected to rise to 15-20% in the future, and NIC has excess storage capacity in main import and secondary depots to accommodate private importers. The proposed transshipment terminal, as well as the depots, should be operated on an open access basis, making it possible for private importers to store their products. - 63 - Recommended Action Plan 5.37 The following sequence of actions will be needed to secure a reliable supply of petroleum products in the country and to ensure the efficient distribution of products in Ulaanbaatar as well as the aimaks: 1. Secure a long-term contract with Angarsk refinery. 2. Evaluate options for securing a long-term contract with a Chinese refinery or for making swap arrangements for products imported through China. 3. Evaluate the construction of a transshipment facilit, X .7amyn-lTud under following scenarios: a) supplies from Achinsk versus other sources in terms of landed cost; and b) merits of risk diversification, taking account of the cost of rationing in case of disruption of supplies. 4. Accelerate efforts to devise explicit regulation to allow foreign and local private investors to import, distribute and market products, and to operate filling stations. 5. Accelerate price liberalization, eiimination of the coupon system for gasoline purchases, and lifting of the uniform pricing policy. 6. Provide TA to NIC to improve their operational procedures, particularly in evaluating options to improve the distribution system. Table 1: 1993 Commercial Energy Balance Sheet (mloe) C1 Electrcily Ht Gasoline Diesel Oil Av. Gas JetFl Fuel Oil Lubricants TOTAL Primary Energy Supply: Primary energy output 1,734.4 1,734.4 Import 17.1 169.4 244.7 1.5 22.3 53.() 8.8 516.7 Export -1.7 -1.7 Change in inventory 44.3 -7.9 -79.5 -1. 1 -3.2 16.(0 -1.7 -33.1 Prinary Energy Available 1,778.7 15.4 161.5 165.2 0.4 19.1 69.0 7.1 2,216.3 Energy Conversion: Thertmal power -1,312.8 721.3 696.9 -53.0 -52.3 Conversion losses -469.9 -112.2 -582.1 Gross Suipply Available 465.8 266.8 584.7 161.5 112.2 0.4 19.1 16.6 7.1 1,634.2 Station Use and Losses: Station use -71.0 -71.0 Transmission/Distribution losses -24.9 -169.1 -194.1 Net .Supply Available 465.8 170.8 415.5 161.5 112:2 0.4 19.1 16.6 7.1 1,369.1 Consumption by Sector: Industry & construction 246.1 117.0 114.7 25.5 16.6 519.9 Transport & colinnunication 8.9 161.5 35.8 0.4 19.1 225.6 Agriculture 16.2 4.4 32.4 53.0 Communal housing & public serv. 157.6 26.9 239.1 1.6 425.2 Othersectors 46.0 13.6 61.7 17.0 7.1 145.4 Total Final Consumption 465.8 170.8 415.5 161.5 112.2 0.4 19.1 16.6 7.1 1,369.1 o Annex 2 - 65 - Page I of 2 Annex 2 Four-Year Rehabilitation Plan CHP Plant No. 4 1. The CES has five coal-fired power-heat cogeneration power plants, with an installed capacity of 793.5 MW electricity and 4873 MW heat capacity (steam and hot water), that burn coal from Baga Nuur, Sharyn Gol, Shivee Ovoo and other mines. The total coal consumption in 1993 was 4.2 million tons. Power and heat production in 1993 was 1,928 GWh and 4,266 Tcal. 2. The cogeneration plants are of the extraction type. Part of the steam is extracted from the turbines for heating load (steam and hot water) and the remaining part of the steam flow is condensed by cooling water. With the exception of the Chinese- made CHP Plant No. 2, all other plants were manufactured in the former Soviet Union. The years of initial operation of units started from 1961 to 1991. 3. Major issues in operation of the cogeneration plants are: (a) low availability of the units; and (b) lack of operationability to meet with peak load demand. The current availability factors of plants are relatively low. In the case of the three plants in Ulaanbaatar, the availabilities of power, hot water and steam in 1994 were about 63.8%, 50.2% and 62.7%. The main causes of the relatively lower availabilities were obsolete designs, poor maintenance, lack of spare parts and poor quality of coal. Coal issues include large variations of actual calorific values (1,300- 3,700 Kcal/kg against 3,500 of design value in the case of Sharyn Gol coal) that result in unstable combustion and requirement for assistance oil combustion; inclusion of foreign materials in coal; high volatile matter which results in explosion; and high moisture content (Shivee Ovoo coal) which results in formation of frozen blocks in winter time and disrupts transportation. The units are not suitable for compensating for load fluctuations and peak load requirements. For peaking requirements, the CES purchases power from the Siberian network of the former Soviet Union. 4. Rehabilitation of CHP Plants No. 3 and No. 4 will increase the system's availability and reduce forced outage rates. The rehabilitation of CHP Plant No. 3 will cost about $40 million and it will be partially funded by ADB. The rehabilitation of CHP Plant No. 4 will cost about $70 million. Japan provided grants of about $20 million in 1993 and 1994, which was used for a limited scope of rehabilitation for emergency measures to prevent accidents and reinforce safety and environmental requirements, and will provide an OECF loan of $45 million for further rehabilitation which will include rehabilitation for boilers, electrostatic precipitators, and instrumentation and control systems. Major items which need rehabilitation in sequence of priority are: (a) boilers; (b) coal feed system and mills; (c) electrostatic precipitators, (d) instrumentation and control systems; (e) turbine-generators; (f) power transformers; and (g) others. Direct Firing Boilers (DFB) instead of the existing "bin system" will increase reliability of the plants. Annex 2 - 66 - Page 2 of 2 5. A proposed rehabilitation scheme for the #4 plant is shown below. For the first year: - Complete rehabilitation for two units (out of eight) of boilers and auxiliaries (mills, coal feed system, fans, etc.). - Repair for other two boilers and auxiliaries. - Complete rehabilitation for two units of turbine generators and auxiliaries. - Complete rehabilitation for two units of transformers, coal crusher and wagon tumbler. * For the second year: - Complete rehabilitation of next two units of boilers and auxiliaries. - Reconstruction for DFB instead of Bin System for one boiler (Optional). - Repair for two boilers and auxiliaries. - Complete rehabilitation of two units of turbine generators and auxiliaries and transformers. * For the third year: - Complete rehabilitation of third group of two units of boilers and auxiliaries. - Accumulation of experience of "DFB". - Complete rehabilitation of two units turbine generators and auxiliaries and transformers. * For the fourth year: - Complete rehabilitation of fourth group of two units of boilers and auxiliaries. - Reconstruction for DFB for two units (option). 6. Estimated costs are about $16.4 million for the rehabilitation for the first year and $12.3 million for reconstruction of DFB for one boiler. 7. After the implementing the rehabilitation, the reliability and availability of the plants will be increased. In the case of CHP Plant No. 4, it is expected that the implementation of the first year rehabilitation will produce a 10% increase in production of electricity and heat, and after the rehabilitation of all units, production will increase by 20%-30%. IBRD 26618 .R' 92. 96- 100 Io 1.08ie )12- 11;6' 120- 52- 52-- MONGOLIA ISOLATED DIESEL POWER SYSTEMS RUSSAN EDERTIO HO- UNIT CAPACITIES BY AIMAG (PROVINCE) 4.1 2 2olS kw 0 s 72o630kW Wr I' *' ~~~~~~~~~~~~320kw" HOv'GOL BULGAN RAY_- .G~I - 200k kWron' C' \ , 200 kA A - E ) B l: 2x300 kW C20 k6oko_ c I ~~~~~.'l 00 kW~~~330 kWNOnndr2o 35 46y60 kW.) 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